N.D. Admin. Code Title 43 — Industrial Commission

Article 43-01 General Administration

Chapter 43-01-01 Organization of Industrial Commission

N.D. Admin. Code 43-01-01-01 Organization of industrial commission

1.History. The 1919 legislative assembly passed legislation, codified as North Dakota Century Code chapter 54-17, creating the industrial commission of North Dakota. The industrial commission was created to conduct and manage, on behalf of the state of North Dakota, certain utilities, industries, enterprises, and business projects established by law.

The 1953 legislative assembly passed oil and gas conservation legislation, codified as North Dakota Century Code chapter 38-08, which gave the industrial commission jurisdiction and

authority over all persons and property, public and private, necessary to enforce the provisions of the legislation.

The 1967 legislative assembly passed legislation, codified as North Dakota Century Code

chapter 38-12, for the regulation, development, and production of subsurface minerals. It gave the industrial commission jurisdiction and authority over all persons and property, public and private, necessary to enforce the provisions of the legislation.

The 1975 legislative assembly passed legislation, codified as North Dakota Century Code

chapter 38-12.1, requiring the filing of coal exploration data with the state geologist. It gave the industrial commission jurisdiction and authority over all persons and property, public and private, necessary to enforce the provisions of the legislation.

The 1989 legislative assembly passed legislation, codified as North Dakota Century Code

chapter 54-17.4, transferring jurisdiction and authority over the geological survey from the board of higher education to the industrial commission. The geological survey serves as the primary source of geological information in the state.

The industrial commission is responsible for establishing the criteria for submission and consideration of research, development, and marketing proposals and entering into contracts under the lignite research, development, and marketing program.

2.Industrial commission membership and quorum. The industrial commission consists of the governor, the attorney general, and the commissioner of agriculture. The governor and one member constitutes a quorum for the transaction of business.

3.Chairman and attorney for the industrial commission. The governor is the chairman of the industrial commission, and its attorney is the attorney general of the state. In its transaction of its general business, the industrial commission may employ secretaries and other subordinate officers, clerks, and agents, on such terms as it may deem proper, appointing and discharging all persons so engaged when and as, in its judgment, the public interest may require.

4.Inquiries. Inquiries regarding the industrial commission may be addressed to the executive director and secretary for the commission:

Mrs. Karlene Fine State Capitol 600 East Boulevard Bismarck, North Dakota 58505

History

• History: Amended effective March 1, 1992; April 1, 1994.
• General Authority: NDCC 28-32-02.1
• Law Implemented: NDCC 28-32-02.1

Article 43-02 Mineral Exploration and Development

Chapter 43-02-01 Coal Exploration

N.D. Admin. Code 43-02-01-01 Definitions

The terms used throughout this chapter have the same meaning as in North Dakota Century Code

chapter 38-12.1.

History

• Law Implemented: NDCC 38-12.1-03

N.D. Admin. Code 43-02-01-02 Scope of chapter

This chapter is of statewide application and has been adopted by the industrial commission to accumulate basic coal exploration data in order to better serve the public interest and to assist the state in determining what the attitude of the state should be regarding the development of coal resources.

Special rules and orders will be issued when required and shall prevail as against this chapter, if in conflict therewith. Wherever this chapter does not conflict with special rules hereafter adopted, this

chapter will apply in each case. The commission may grant exceptions to this chapter, after due notice and hearing, when such exceptions will result in a greater benefit to the state and will protect the interests of all persons.

History

• Law Implemented: NDCC 38-12.1-02

N.D. Admin. Code 43-02-01-03 Promulgation of rules, regulations, or orders

No rule, regulation, or order, including change, renewal, or exception thereof, shall, in the absence of an emergency, be made by the commission, except after a public hearing on at least ten days' notice given in the manner prescribed by law. The public hearing shall be held at such time and place and in such a manner as may be prescribed by the commission, and any person having any interest in the subject matter of the hearing shall be entitled to be heard.

N.D. Admin. Code 43-02-01-04 Emergency rule, regulation, or order

In the event an emergency is found to exist by the commission which in its judgment requires the making, revoking, amending, modifying, altering, enlarging, renewing, or extending of a rule, regulation, or order without first holding a hearing after due notice, such emergency rule, regulation, or order shall have the same validity as if a hearing after due notice with respect to the same had been held.

The emergency rule, regulation, or order permitted by this section shall remain in force no longer than fifteen days from its effective date. It shall expire when the rule, regulation, or order made after due notice and hearing with respect to the subject matter of the emergency rule, regulation, or order becomes effective. In no event shall the emergency rule, regulation, or order remain in effect longer than fifteen days.

History

• Law Implemented: NDCC 38-12.1-06

N.D. Admin. Code 43-02-01-05 Enforcement

The commission, its agents, representatives, and employees are charged with the duty and obligation of enforcing all rules and statutes of the state of North Dakota relating to coal exploration and evaluation.

It shall be the responsibility of all permit applicants and permitholders to obtain information pertaining to the regulation of coal exploration and evaluation before the operations of the permit applicants and permitholders have begun.

Whenever a corporate permittee violates North Dakota Century Code chapter 38-12.1 or any permit condition or rule implemented thereunder, a director, officer, or agent of the corporate permittee who knowingly causes such violation is subject to the criminal penalties imposed under subsection 2 of North Dakota Century Code section 38-12.1-08. "Knowingly" is to be understood as defined by North Dakota Century Code section 12.1-02-02. In addition, whenever a director, officer, or agent of a corporate permittee willfully or negligently violates North Dakota Century Code chapter 38-12.1 or any permit condition or rule implemented thereunder, civil penalties may be imposed under subsection 1 of North Dakota Century Code section 38-12.1-08. "Willfully" and "negligently" are to be understood as defined by North Dakota Century Code section 12.1-02-02.

History

• History: Amended effective April 1, 1994.
• Law Implemented: NDCC 38-12.1-04, 38-12.1-07, 38-12.1-08

N.D. Admin. Code 43-02-01-06 United States government leases

The commission recognizes that all persons exploring on United States government land or for United States government minerals shall comply with the federal regulations. Such persons shall also comply with all applicable state rules and regulations which are not in conflict with federal regulations, except that no fee shall be required or a permit application if such permit is a permit to explore on United States government land. All other rules, regulations, and orders apply to permit applicants and permitholders where the permit in question covers United States government land, including the requirement that the permitholder shall furnish the state geologist with copies of the basic data reports, with no charge to the state geologist.

N.D. Admin. Code 43-02-01-07 Forms upon request

Forms for written notices, requests, and reports required by the commission will be furnished upon request. These forms shall be of such a nature as prescribed by the commission covering proposed work, work in progress, and the results of completed work.

N.D. Admin. Code 43-02-01-08 Authority to cooperate with other agencies

The commission may from time to time enter into arrangements with state and federal government agencies, committees from industry, and individuals with respect to special projects, services, and studies relating to coal exploration.

N.D. Admin. Code 43-02-01-09 Record of permits

The state geologist shall maintain an official permit list in which shall be entered:

1.The name of the permitholder.

2.The permit number.

N.D. Admin. Code 43-02-01-10 Bond

Any person engaged in coal exploration and evaluation, or who proposes to do so, shall submit to the commission and obtain its approval of a surety bond or cash bond. An alternate form of security may be approved by the commission after notice and hearing, as provided by law, and such bond shall be required for each permit area. The bond shall be in the amount of one hundred dollars for each testhole drilled in the permit area. Each such surety bond shall be executed by a responsible surety company, authorized to transact business in the state of North Dakota. A blanket bond in the amount of ten thousand dollars, conditioned as above provided, may be submitted to cover any number of testholes drilled in one or more permit areas. The blanket bond shall cover all permits issued in one year commencing on the date the first permit covered by the bond is issued.

Any person providing a blanket bond in lieu of several individual bonds is required to comply with the rules, regulations, and orders of the commission in the same manner as if the person had provided several individual bonds. Violation shall result in forfeiture of the blanket bond in its entirety, if the violation would have resulted in forfeiture had the action in question been covered by an individual bond.

For the purposes of the commission the bond required is a performance bond, as well as a plugging bond, and is to endure up to and including receipt by the state geologist of all basic exploration data required by law and approved plugging of all holes drilled.

The commission will in writing advise the principal and sureties on any surety bond as to whether the provisions of statutes and rules have been satisfied, and that liability under the bond may be formally terminated.

The state geologist is vested with the power to act for the commission as to all matters within this

section.

Any state or federal agency engaged in coal exploration or evaluation shall be exempt from providing the bond.

History

• History: Amended effective May 1, 2004.

N.D. Admin. Code 43-02-01-11 Public availability of permit application information

1.Except as provided in subdivisions a, b, and c, all information submitted to the commission with a permit application for coal exploration shall be made available for public inspection and copying at the office of the state geologist.

a.The state geologist shall not make information submitted with a coal exploration permit application available for public inspection, if the person submitting it requests in writing, at the time of permit application submission, that it not be disclosed and the state geologist determines that the information is confidential. However, such information shall remain confidential only for the time period specified in North Dakota Century Code

section 38-12.1-04.

b.The state geologist shall determine that permit application information is confidential only if it concerns trade secrets or is privileged commercial or financial information which relates to the competitive rights of the person intending to conduct coal exploration.

c.Information requested to be held as confidential under this subsection shall not be made publicly available until after proper notice and hearing before the commission.

2.Basic data collected during the course of the exploration and submitted to the state geologist shall be confidential and available only to the office of the state geologist. The period of confidentiality shall continue for a period of two years, beginning on the expiration date of the permit. One year extensions shall be granted if an application for extension is filed with the state geologist prior to the expiration date of the confidentiality period. In no event shall the total period of confidentiality exceed the time period specified in North Dakota Century Code

section 38-12.1-04.

3.The permitholder may waive the holder's right to confidentiality by providing written notice of the waiver to the state geologist.

History

• History: Amended effective August 1, 1980; December 1, 1992.

N.D. Admin. Code 43-02-01-12 Basic data

Basic data developed by or for the person conducting the coal exploration or evaluation, consisting of testhole locations, testhole elevations, total depths, driller's logs, radioactivity, resistivity, or other types of electrical or mechanical logs shall be delivered free of charge to the state geologist within six months of the expiration date of the permit covering the exploration or evaluation.

Sample cuts, portions of cores not required for analysis, or core analyses developed by or for the person conducting the coal exploration or evaluation shall also be submitted free of cost to the state geologist if requested.

History

• History: Amended effective March 1, 1991.

N.D. Admin. Code 43-02-01-13 Reports

Quarterly progress reports, listing locations of testholes completed and plugged, shall be filed by the twenty-fifth day of January, April, July, and October by all permitholders. If no drilling occurred during the quarter, a report so stating shall be filed.

Completion reports shall also be filed upon completion of the exploration or evaluation, or upon the expiration of the permit, whichever occurs first, by all permitholders. The completion reports shall include all progress on exploration and evaluation and any other information requested by the state geologist.

N.D. Admin. Code 43-02-01-14 Method of plugging

Before any testhole is abandoned, all of the cuttings possible must be returned to the testhole, and it shall be plugged in such a manner as to prevent the intrusion of any foreign material. Any cuttings not returned to the hole must be spread at the surface, if approved by the landowner, or properly disposed of off the testhole site, if approved by the owner of the disposal site. The plugging shall be accomplished immediately when all desired information has been obtained.

If a testhole penetrates water bearing sands it shall be plugged with cement or some other method approved by the state geologist, in such a manner as to permanently confine the water to its original stratum.

History

• History: Amended effective August 1, 1986.

N.D. Admin. Code 43-02-01-15 Testholes to be used for freshwater

When a testhole to be plugged may safely be used as a freshwater well, and such utilization is desired by the landowner, the testhole need not be filled above a sealing plug set below the freshwater aquifer; provided, that written authority and assumption of liability for such use and plugging shall be secured from the landowner and filed with the state geologist. The person conducting the coal exploration shall be relieved of that person's responsibility under this chapter.

The landowner assuming ownership and liability for the testhole shall comply with the rules for water well construction and water well pump installation pursuant to North Dakota Century Code

chapter 43-35.

N.D. Admin. Code 43-02-01-16 Confining of water to their original strata

During the drilling of any testhole, all freshwaters and waters of present or probable value for domestic, commercial, or stock purposes encountered shall be confined to their respective strata and shall be adequately protected by methods approved by the state geologist. Special precautions shall be taken in drilling and abandoning of testholes to guard against any loss of artesian water from the strata in which it occurs, and to prevent contamination of artesian water by objectionable water.

N.D. Admin. Code 43-02-01-17 Inspection

The state geologist or the state geologist's representative shall have access to all drilling or exploration installations regulated under this chapter for the purpose of inspection and sampling. The state geologist may require the aid of the permitholder if the state geologist finds such aid necessary, and if the state geologist requests such aid.

If samples are to be collected by the state geologist, details relating to the starting date of the collection of such samples and the drill site locations shall be worked out between the state geologist or the state geologist's agents and the permitholder or the permitholder's agents prior to the starting date of such collection.

N.D. Admin. Code 43-02-01-18 Permits

A permit shall be required prior to commencement of operations for the exploration and evaluation of coal, except as provided in subsection 2 of North Dakota Century Code section 38-12.1-05. A permit shall be granted for one year upon receipt of a permit application, on a form provided by the commission, and the furnishing of a bond, as set out in this chapter, and the payment of a fee of one hundred dollars per permit. A permit shall be valid for one permit area only, and only for those exploration operations which will remove less than two hundred fifty tons [226.80 metric tons] of coal from a permit area. The removal of more than two hundred fifty tons [226.80 metric tons] of coal from an area shall be considered a surface coal mining operation and shall be subject to the requirements of North Dakota Century Code chapter 38-14.1 and the regulations of the public service commission promulgated thereunder.

1.So that the state geologist can decide if a permit is required, notice of all planned environmental data gathering activities, except for those specified in subsections 2 and 3, must be provided to the state geologist before beginning any such activities. The notice must include:

a.The name, address, and telephone number of the person seeking to conduct environmental data gathering activities.

b.The name, address, and telephone number of the person's representative who will be present at and will supervise the activities.

c.A narrative describing the activities or a map at a scale of one to twenty-four thousand, or greater, showing the proposed area of activities and the general location of drill holes and trenches, existing and proposed roads, occupied dwellings, topographic features, bodies of surface water, and pipelines.

d.A statement of the period of the planned activities.

e.A description of all the environmental data gathering activities and the practices that will be followed to protect the environment and to reclaim the area from adverse impacts of the activities as required by this chapter.

2.The notice required by this section is not required for the following activities: fish and wildlife surveys, premine land use determinations, vegetation surveys, collection of climatological data, topographical surveys, and walk-through cultural resource surveys.

3.Notice is not required for environmental data gathering activities on lands designated as unsuitable for mining under North Dakota Century Code section 38-14.1-05. However, an exploration permit from the state geologist is required for those activities on such lands.

History

• History: Amended effective August 1, 1980.
• General Authority: NDCC 38-12.1-05 43-02-01-18.1. Notice of environmental data gathering activities.
• History: Effective March 1, 1991; amended effective May 1, 1992.
• General Authority: NDCC 38-12.1-05

N.D. Admin. Code 43-02-01-19 Contents of permit application

The permit application shall include:

1.The name, address, and telephone number of the person seeking to explore.

2.The name, address, and telephone number of the representative who will be present at and responsible for conducting the exploration activities.

3.A precise description of the exploration area.

4.A statement of the period of intended exploration.

5.A description of the practices proposed to be followed to protect the environment from adverse impacts as a result of the exploration activities.

6.A statement by the permit applicant that the applicant will comply with all of the coal exploration performance standards of article 43-02 for all coal exploration and reclamation which substantially disturbs the natural land surface.

7.Any other information required by the commission.

History

• History: Effective August 1, 1980.
• General Authority: NDCC 38-12.1-03, 38-12.1-05

N.D. Admin. Code 43-02-01-20 Performance standards for coal exploration

The performance standards in this section are applicable to coal exploration which substantially disturbs land surface and on land designated unsuitable for mining under North Dakota Century Code

section 38-14.1-05. Whether the land surface will be substantially disturbed shall be determined by the state geologist.

1.For purposes of this section, "substantially disturb" means, for purposes of coal exploration, to impact significantly upon land, air, or water resources by such activities as blasting, mechanical excavation, drilling or altering coal or water exploratory holes or wells, construction of roads and other access routes, and the placement of structures, excavated earth, or other debris on the surface of land.

2.Coal exploration activities which will substantially disturb land surface shall not be allowed to affect the following:

a.Habitats of unique value for fish, wildlife, and other related environmental values.

b.Threatened or endangered species of plants or animals listed by the Endangered Species Act of 1973, as amended [16 U.S.C. 1531 et seq.] and their critical habitats.

c.Species such as eagles, migrating birds or other animals protected by state or federal law, and their habitats.

d.Habitats of unusually high value for fish and wildlife, such as wetlands, riparian areas, cliffs, supporting raptors, areas offering special shelter or protection, reproduction and nursery areas, and wintering areas.

3.The person who conducts coal exploration shall, to the extent practicable, measure important environmental characteristics of the exploration area during the operations, to minimize environmental damage to the area and to provide supportive information for any permit application that person may submit as part of the permit application.

a.Vehicular travel on other than established graded and surfaced roads shall be limited by the person who conducts coal exploration to that absolutely necessary to conduct the exploration. Travel shall be confined to graded and surface roads during periods when excessive damage to vegetation or rutting of the land surface could result.

b.Any new road in the exploration area shall comply with the provisions of chapter 69-05.2-24.

c.Existing roads may be used for exploration in accordance with the following:

(1)All applicable federal, state, and local requirements shall be met.

(2)If the road is significantly altered for exploration, including, but not limited to, change of grade, widening, or change of route, or if use of the road for exploration contributes additional suspended solids to streamflow or runoff, then subsection 7 and subsections 1 and 2 of section 69-05.2-24-01 shall apply to all areas of the road which are altered or which result in such additional contributions. A road is altered if it is constructed, reconstructed, improved, or maintained in any way that causes the changes described in this section.

(3)If the road is significantly altered for exploration activities and will remain as a permanent road after exploration activities are completed, the person conducting exploration shall ensure that the requirements of chapter 69-05.2-24, as appropriate, are met for the design, construction, alteration, and maintenance of the road.

d.Promptly after exploration activities are completed, existing roads used during exploration shall be reclaimed either:

(1)To a condition equal to or better than their preexploration condition; or (2)To the condition required for permanent roads under chapter 69-05.2-24, as appropriate.

4.If excavations, artificial flat areas, or embankments are created during exploration, these areas shall be returned to the approximate original contour promptly after such features are no longer needed for coal exploration.

5.Suitable plant growth material, as defined in subsection 31 of North Dakota Century Code

section 38-14.1-02 shall be removed, stored, and redistributed on disturbed areas as necessary to assure successful revegetation or as required by the commission.

6.Revegetation of areas disturbed by coal exploration shall be performed by the person who conducts the exploration or the person's agent. All revegetation shall be in compliance with the plan approved by the commission and carried out in a manner that encourages prompt vegetative cover and recovery of productivity levels compatible with approved postexploration land use and in accordance with the following:

a.All disturbed lands shall be seeded or planted to the same seasonal variety native to the disturbed area or to some suitable, commercially available mixture approved by the state geologist. If both the preexploration and postexploration land uses are intensive agriculture, planting of the crops normally grown will meet the requirements of this

section.

b.The vegetative cover shall be capable of stabilizing the soil surface in regards to erosion.

7.With the exception of small and temporary diversions of overland flow of water around new roads, drill pads, and support facilities, no ephemeral, intermittent or perennial stream shall be diverted during coal exploration activities. Overland flow of water shall be diverted in a manner that:

a.Prevents erosion.

b.To the extent possible using the best technology currently available, prevents additional contributions of suspended solids to streamflow or runoff outside the exploration area.

c.Complies with all other applicable state or federal requirements.

8.Each exploration hole, borehole, well, or other exposed underground opening created during exploration must be cased or sealed to meet the requirements of chapter 69-05.2-14 and

section 43-02-01-14.

9.All facilities and equipment shall be removed from the exploration area promptly when they are no longer needed for exploration, except for those facilities and equipment that the state geologist determines may remain to:

a.Provide additional environmental quality data.

b.Reduce or control the onsite or offsite effects of the exploration activities.

c.Facilitate future surface mining and reclamation operations by the person conducting the exploration, under an approved permit.

10.Coal exploration shall be conducted in a manner which minimizes disturbance of the prevailing hydrologic balance, and shall include appropriate sediment control measures such as those specified in section 69-05.2-16-08. The commission may specify additional measures which shall be adopted by the person engaged in coal exploration.

11.Toxic-forming materials shall be handled and disposed of in accordance with sections 69-05.2-16-11 and 69-05.2-21-03. If specified by the commission, additional measures shall be adopted by the person engaged in coal exploration.

History

• History: Effective August 1, 1980; amended effective March 1, 1991; April 1,1994.

N.D. Admin. Code 43-02-01-21 Removal of coal

No coal shall be extracted for commercial sale during a coal exploration operation. No other coal shall be extracted except for cores and samples necessary for testing and analysis.

History

• History: Effective August 1, 1980.

Chapter 43-02-02 Subsurface Mineral Exploration and Development

N.D. Admin. Code 43-02-02-01 Definitions

The terms used throughout this chapter have the same meaning as in North Dakota Century Code

chapter 38-12, except:

1."Barrel" means forty-two United States gallons [158.99 liters] measured at sixty degrees Fahrenheit [15.56 degrees Celsius] and fourteen and seventy-three hundreths pounds per square-inch absolute [1034.19 grams per square centimeter].

2."Bottom hole or subsurface pressure" means the pressure in pounds per square-inch gauge under conditions existing at or near the producing horizon.

3."Certified or registered mail" means any form of service by the United States postal service, federal express, Pitney Bowes, and any other commercial nationwide delivery service that provides the mailer with a document showing the date of delivery or refusal to accept delivery.

4."Completion" means when the well is capable of producing subsurface minerals through wellhead equipment from the ultimate producing zone after casing has been run.

5."Deep well" means any well to explore for, develop, or produce subsurface minerals which is drilled into rocks older than the Greenhorn formation or which encounters brackish or saline formation waters.

6."Department" means the department of mineral resources of the industrial commission.

7."Deposit" means an underground concentration containing a common accumulation of subsurface minerals.

8."Director" means the director of the department of mineral resources of the industrial

9."Exception location" means a location which does not conform to the general spacing requirements established by the rules or orders of the commission but which has been specifically approved by the commission.

10."Field" means the general area underlaid by a concentration of subsurface minerals. Field also includes the geological formation containing such subsurface minerals.

11."Log or well log" means a systematic, detailed, and correct record of formations encountered in the drilling of a well, and includes commercial electrical logs and similar records.

12."Nonhydrocarbon gas" means all naturally occurring gaseous elements and compounds except hydrocarbons and carbon dioxide as regulated under North Dakota Century Code

chapter 38-08.

13."Occupied dwelling" means a residence which is lived in by a person at least six months throughout a calendar year.

14."Operator" means any person or persons who, duly authorized, is in charge of the development of a lease or the operation of a producing property.

15."Product" means any commodity made from any subsurface mineral.

16."Recomplete" means the subsequent completion of a well in a different pool.

17."Reservoir" means a pool or common source of supply.

18."Saltwater handling facility" means and includes any container, such as a pit, tank, or pool, whether covered or uncovered, used for the handling, storage, disposal of deleterious substances obtained, or used, in connection with the drilling or operation of wells.

19."Shallow well" means any well drilled into rocks younger than the Belle Fourche formation which does not encounter saline or brackish formation waters for the purpose of developing or producing subsurface minerals.

20."Shut-in pressure" means the pressure noted at the wellhead when the well is completely shut in, not to be confused with bottom hole pressure.

21."Testhole" means any hole drilled to a total depth of less than one thousand feet [304.8 meters] for the purpose of gathering information on subsurface minerals.

22."Waste" means:

a.Physical waste;

b.Operations which cause or tend to cause unnecessary or excessive surface loss; or

c.Operations that do not recover all of the mineral being mined that is technically and economically possible.

N.D. Admin. Code 43-02-02-02 Scope of chapter

This chapter contains general rules of statewide application which have been adopted by the industrial commission to conserve the natural resources of North Dakota, to prevent waste, and to provide for operation in a manner as to protect correlative rights of all owners of subsurface minerals.

Special rules, pool rules, field rules, and regulations and orders have been and will be issued when required and shall prevail as against general rules, regulations, and orders if in conflict therewith.

However, wherever this chapter does not conflict with special rules heretofore or hereafter adopted, this

chapter will apply in each case. The commission may grant exceptions to this chapter, after due notice and hearing, when such exceptions will result in the prevention of waste and operation in a manner to protect correlative rights.

N.D. Admin. Code 43-02-02-03 Promulgation of rules, regulations, or orders

N.D. Admin. Code 43-02-02-04 Emergency rule, regulation, or order

N.D. Admin. Code 43-02-02-05 Enforcement of laws, rules, and regulations dealing with exploration, development, and production of subsurface minerals

The commission, its agents, representatives, and employees are charged with the duty and obligation of enforcing all rules and statutes of North Dakota relating to the exploration, development, and production of subsurface minerals. However, it shall be the responsibility of all owners or operators to obtain information pertaining to the regulation of subsurface minerals before operations have begun. 43-02-02-05.1. Waste prohibited.

All operators, contractors, drillers, carriers, gas distributors, service companies, pipe pulling and salvaging contractors, or other persons shall at all times conduct their operations in the mining, drilling, equipping, operating, producing, plugging, and site reclamation of subsurface minerals in a manner that will prevent waste.

N.D. Admin. Code 43-02-02-06 United States government leases

The commission recognizes that all persons drilling and producing on United States government land shall comply with the United States government regulations. Such persons shall also comply with all applicable state rules and regulations. Copies of the sundry notices, reports on wells, and well data required by this chapter of the wells on United States government land shall be furnished to the state geologist at no expense to the state geologist. Federal forms may be used when filing such notices and reports except for reporting the plugging and abandonment of a well. In such instance, the plugging record (form 7-sm) must be filed with the state geologist.

N.D. Admin. Code 43-02-02-07 Forms upon request

Forms for written notices, requests, and reports required by the commission will be furnished upon request. These forms shall be of such nature as prescribed by the commission to cover proposed work and to report the results of completed work.

N.D. Admin. Code 43-02-02-08 Authority to cooperate with other agencies

The commission may from time to time enter into arrangements with state and federal government agencies, industry committees, and individuals with respect to special projects, services, and studies relating to subsurface minerals.

N.D. Admin. Code 43-02-02-09 Organization reports

Every person acting as principal or agent for another or independently engaged in the drilling for, or in the production, storage, transportation, refining, reclaiming, treating, marketing, or processing of subsurface minerals in North Dakota shall immediately file with the state geologist the name under which such business is being conducted and operated; the name and post-office address of such person; the business or businesses in which the person is engaged; the plan of organization, and in case of a corporation, the law under which it is chartered; and the names and post-office addresses of any person acting as trustee, together with the names and post-office addresses of any officials on an organization report (form 2sm). If such business is conducted under an assumed name, such organization report shall show the names and post-office addresses of all owners in addition to the other information required. A new organization report shall be filed when and if there is a change in any of the information contained in the report. 43-02-02-09.1. Reservoir surveys.

By special order of the commission, periodic surveys may be made of the reservoirs in the state containing subsurface minerals. These surveys will be thorough and complete and shall be made using methods approved by the director. The condition of the reservoirs containing subsurface minerals and the practices and methods employed by the operators shall be investigated. The produced volume and source of subsurface mineral, reservoir pressure of the reservoir as an average, the areas of regional or differential pressure, and producing characteristics of the field as a whole and the individual wells within the field shall be specifically included.

All operators of mineral wells are required to permit and assist the agents of the commission in making any and all special tests that may be required by the commission on any or all wells.

N.D. Admin. Code 43-02-02-10 Record of permits and official well names

The state geologist shall maintain an official permit list and a record of official well names.

1.The official permit list must include:

a.The name of the permitholder;

b.The permit number;

c.The date the permit was issued; and

d.The location of the permit.

2.The record of official well names, to be known as the well name register, must include:

a.The name and location of each well;

b.The well file number;

c.The name of the operator or operator's agent; and

d.Any subsequent name or names assigned to the well and approved by the director.

The last name assigned to a well in the well name register shall be the official name of the well, and the one by which it shall be known and referred to.

The director may, at the director's discretion, grant or refuse an application to change the official name. The application shall be accompanied by a fee of twenty-five dollars, which fee is established to cover the expense of recording the change. If the application is refused, the fee shall be refunded. 43-02-02-10.1. Access to records.

The commission, director, and their representatives shall have access to all well records wherever located. All owners, operators, drilling contractors, drillers, service companies, or other persons engaged in drilling, completing, producing, or servicing wells shall permit the commission, director, and their representatives to come upon any lease, property, well, or drilling rig operated or controlled by them, complying with state safety rules and to inspect the records and operation of such wells, and to have access at all items to any and all records of wells. If requested, copies of such records must be filed with the commission. The confidentiality of any data submitted which is confidential pursuant to subdivision b of subsection 1 of North Dakota Century Code section 38-12-02 and North Dakota Administrative Code section 43-02-02-22 must be maintained.

N.D. Admin. Code 43-02-02-11 Bond

Before any person receives a permit to explore for or produce subsurface minerals, the person shall submit to the commission and obtain its approval of a surety bond or cash bond. An alternate form of security may be approved by the commission after notice and hearing, as provided by law. The operator of a well or facility shall be the principal on the bond covering such activity. Each such surety bond shall be executed by a responsible surety company authorized to transact business in North Dakota.

1.Bond amounts and limitations for projects that involve drill holes:

a.For wells drilled to a total depth of less than two thousand feet [609.6 meters], the amount of the bond shall be commensurate with the number of wells, the type of project, and the environmental risk. The amount of a bond will be determined by a formula that assigns reclamation costs based upon the number of drill sites, the depths of the holes, and the anticipated surface restoration costs.

b.For wells drilled to a total depth of two thousand feet [609.6 meters], or more, the bond shall be in the amount of fifty thousand dollars and applicable to one well only.

When the principal on the bond is drilling or operating a number of wells within the state or proposes to do so, the principal may submit a bond conditioned as provided by law. A well with an approved temporary abandoned status shall have the same status as an exploratory, mineral, or injection well. The commission may, after notice and hearing, require higher bond amounts than those required by this section. Such additional amounts for bonds must be related to the economic value of the well or wells and the expected cost of plugging and well site reclamation, as determined by the commission.

2.Bond terms. Bonds shall be conditioned upon full compliance with North Dakota Century Code

chapter 38-12, and all administrative rules and orders of the commission, and continues until any of the following occurs:

a.The testholes or wells have been satisfactorily plugged which shall include practical reclamation of the well site and appurtenances; and all logs, plugging records, and other pertinent data required by statute or rules and orders of the commission are filed and approved.

b.The mined lands or lands disturbed by any method of exploration or production of subsurface minerals have been restored and approved by the director.

c.The liability on the bond has been transferred to another bond and such transfer approved by the commission.

3.Transfer of property under bond. Transfer of property does not release the bond. In case of transfer of property or other interest in a well, extraction facility, or surface mining facility and the principal desires to be released from the bond covering the well or facility, such as producers, not ready for plugging, the principal must proceed as follows:

a.The principal must notify the director, in writing, of all proposed transfers of property at least thirty days before the closing date of the transfer. The director may, for good cause, waive this requirement.

The principal shall submit to the commission a form 8-sm reciting that a certain property or properties, describing each by quarter-quarter, section, township, and range, is to be transferred to a certain transferee, naming such transferee, for the purpose of ownership or operation. The date of assignment or transfer must be stated and the form signed by a party duly authorized to sign on behalf of the principal.

On said transfer form the transferee shall recite the following: "The transferee has read the foregoing statement and accepts such transfer and the responsibility of such property under the transferee's one-well bond, surface mining facility bond, or extraction facility bond." Such acceptance must be signed by a party authorized to sign on behalf of the transferee and the transferee's surety.

b.When the commission has passed upon the transfer and acceptance and accepted it under the transferee's bond, the transferor shall be released from the responsibility of well plugging and site reclamation. If such wells include all the wells within the responsibility of the transferor's bond, such bond will be released by the commission upon written request. Such request must be signed by an officer of the transferor or a person authorized to sign for the transferor. The director may refuse to transfer any well from a bond if the well is in violation of a statute, rule, or order.

c.The transferee (new operator) of any extraction facility, surface mining facility, or injection well shall be responsible for the plugging and site reclamation of any such property. For that purpose, the transferee shall submit a new bond or, in the case of a surety bond, produce the written consent of the surety of the original or prior bond that the latter's responsibility shall continue and attach to such well. The original or prior bond shall not be released as to the plugging and reclamation responsibility of any such transferor until the transferee submits to the commission an acceptable bond to cover such well. All liability on bonds shall continue until the plugging and site reclamation of such property is completed and approved.

4.Bond termination. The commission shall, in writing, advise the principal and any sureties on any bond as to whether the plugging and reclamation is approved. If approved, liability under such bond may be formally terminated upon receipt of a written request by the principal. The request must be signed by an officer of the principal or a person authorized to sign for the principal.

5.Director's authority. The director is vested with the power to act for the commission as to all matters within this section, except requests for alternative forms of security, which may only be approved by the commission.

The commission may refuse to accept a bond if the operator or surety company has failed in the past to comply with statutes, rules, or orders relating to the operation of wells; if a civil or administrative action brought by the commission is pending against the operator or surety company; or for other good cause.

The principal on the bond covering a well is the operator of the well. The operator is responsible for compliance with all laws relating to the well and well site. A dispute over designation of the operator of a well may be addressed by the commission. In doing so, the factors the commission may consider include those set forth in subsection 1 of section 43-02-02-12.1.

History

• History: Amended effective August 1, 1986; May 1, 2004; October 1, 2008; July 1, 2013. 43-02-02-11.1. Designation and responsibilities of operator.

N.D. Admin. Code 43-02-02-12 Application for permit to drill and recomplete

A permit shall be required prior to commencement of operations for the exploration or evaluation of subsurface minerals. The application for a permit to drill (form 1-sm) shall be filed with the director, together with a permit fee of one hundred dollars. In extenuating circumstances, verbal approval may be given for site preparation by the director. No drilling activity shall commence until such application is approved and a permit to drill is issued by the director. The application must be accompanied by the bond pursuant to section 43-02-02-11 or the applicant must have previously filed such bond with the commission, otherwise the application is incomplete. An incomplete application received by the commission has no standing and will not be deemed filed until it is complete.

A permit shall be required for each deep well not included in an approved mining plan.

A permit shall be required for each testhole drilling program exploring for subsurface minerals. The area to be explored shall be outlined on the application and the permit shall be valid in the area so outlined.

The application for permit to drill shall be accompanied by an accurate plat certified by a registered surveyor showing the location of the proposed well with reference to true north and the nearest lines of a governmental section. The plat shall also include latitude and longitude of the proposed well location to the nearest tenth of a second. Information to be included in such application shall be the proposed depth to which the well will be drilled; estimated depth to the top of important markers; estimated depth to the top of objective horizons; the proposed mud program; the proposed casing program, including size and weight; the depth at which each casing string is to be set; the proposed pad layout, including cut and fill diagrams; and the proposed amount of cement to be used, including the estimated top of the cement.

Prior to the commencement of recompletion operations or drilling horizontally, an application for permit shall be filed with the director. Included in such application shall be the notice of intention (form 4-sm) to reenter a well by drilling horizontally, deepening, or plugging back to any source of supply other than the producing horizon in an existing well. Such notice shall include the name and file number and exact location of the well, the approximate date operations will begin, the proposed procedure, the estimated completed total depth, the anticipated hydrogen sulfide content in produced gas from the proposed source of supply, the weight and grade of all casing currently installed in the well unless waived by the director, the casing program to be followed, and the original total depth with a permit fee of fifty dollars. The director may deny any application if it is determined, in accordance with the latest version of ANSI/NACE MR0175/ISO 15156, that the casing currently installed in the well would be subject to sulfide stress cracking.

The applicant shall provide any additional information requested by the director, in addition to that specifically required by this section. The director may impose such terms and conditions on the permits issued under this section as the state geologist deems necessary.

The director shall deny an application for a permit under this section if the proposal would violate correlative rights or would cause, or tend to cause, waste. The director shall state in writing to the applicant the reason for the denial of the permit. The applicant may appeal the decision of the director to the commission.

A permit to drill automatically expires one year after the date it was issued, unless the well is drilling or has been drilled before surface casing. A permit to recomplete or to drill horizontally automatically expires one year after the date it was issued, unless such project has commenced.

1.After notice and hearing, the commission may revoke a drilling, recompletion, or reentry permit or limit its duration. The commission may act upon its own motion or upon the application of an owner in the spacing or drilling unit. In deciding whether to revoke or limit a permit, the factors that the commission may consider include:

a.The technical ability of the permitholder and other owners to drill and complete the well.

b.The experience of the permitholder and other owners in drilling and completing similar wells.

c.The number of wells in the area operated by the permitholder and other owners.

d.Whether drainage of the spacing or drilling unit has occurred or is likely to occur in the immediate future and whether the permitholder has committed to drill a well in a timely fashion.

e.Contractual obligations, such as an expiring lease.

f.The amount of ownership the permitholder and other owners hold in the spacing or drilling unit. If the permitholder is the majority owner in the unit or if its interest when combined with that of its supporters is a majority of the ownership, it is presumed that the permitholder should retain the permit. This presumption, even if not rebutted, does not prohibit the commission from limiting the duration of the permit. However, if the amount of the interest owned by the owner seeking revocation or limitation and its supporters are a majority of the ownership, the commission will presume that the permit should be revoked.

2.The commission may suspend a permit that is the subject of a revocation or limitation proceeding. A permit will not be suspended or revoked after operations have commenced.

3.If the commission revokes a permit upon the application of an owner and issues a permit to that owner or to another owner who supported revocation, the commission may limit the duration of such permit. The commission may also, if the parties fail to agree, order the owner acquiring the permit to pay reasonable costs incurred by the former permitholder and the conditions under which payment is to be made. The costs for which reimbursement may be ordered may include those involving survey of the well site, title search of surface and mineral title, and preparation of an opinion of mineral ownership.

4.If the commission declines to revoke a permit or limit the time within which it must be exercised, it may include a term in its order restricting the ability of the permitholder to renew the permit or to acquire another permit within the same spacing or drilling unit. 43-02-02-12.2. Design and construction of surface facilities.

The operator shall submit plans and specifications to the director before constructing the following surface facilities:

1.Process or recovery plants and satellite facilities;

2.Ponds and impoundments;

3.Pipelines;

4.Well houses or transfer stations;

5.Fuel storage areas;

6.Any haul roads that will be used for more than six months;

7.Byproduct disposal areas; and

8.Any other facility that may contain substances that could impact human health or degrade the environment if spilled, discharged, or released.

1.The operator shall develop, for the department's approval, a construction quality assurance plan that addresses all aspects of constructing surface facilities. The plan must include the following:

a.A description of the responsibilities and authorities of key personnel, including the personnel's level of experience and training;

b.A description of the required level of experience, training, and duties of the contractor, the contractor's employees, and the quality assurance inspectors;

c.A description of the testing protocols for every major phase of construction, including the frequency of inspections, field testing, and sampling for laboratory testing;

d.The sampling and field testing procedures and the equipment to be used;

e.The calibration of field testing equipment;

f.The laboratory procedures to be used; and

g.A description of the documentation to be maintained.

2.The operator shall submit the construction quality assurance plan at the same time the plans and specifications required in section 43-02-02-12.2 are submitted. 43-02-02-12.4. Pipeline design and construction requirements.

1.Topsoil must be removed before the installation of underground pipelines and replaced after pipelines are installed.

2.Pipeline systems must be constructed with materials that have the strength, thickness, and chemical properties that prevent failure due to pressure gradients, physical contact with the waste or fluids to which the pipes are exposed, climatic conditions, stress of installation, seismic, and stress of daily operation.

3.Design and construction requirements for wellfield pipelines and pipelines between the wellfield and processing and satellite facilities must include an early detection and shutdown capability in the event of pressure drop or loss of flow. This may include automatic motor-operated valves with pressure transmitters and manually operated valves or devices. 43-02-02-12.5. Disposal of liquid waste.

All liquid waste streams must be:

1.Disposed of in a permitted class I or V underground injection control disposal well under a state department of health underground injection control program permit in accordance with

chapter 33-25-01;

2.Land applied under a solid waste permit in accordance with chapter 33-20-09; or

3.Treated, if necessary, and discharged under a North Dakota pollution discharge elimination system surface water discharge permit in accordance with chapter 33-16-01.

History

• History: Amended effective May 1, 2004; July 1, 2013.
• General Authority: NDCC 38-12-03
• Law Implemented: NDCC 38-12-03 43-02-02-12.1. Revocation and limitation of drilling permits.
• General Authority: NDCC 38-12-03
• Law Implemented: NDCC 38-12-03 43-02-02-12.3. Construction quality assurance plan.

N.D. Admin. Code 43-02-02-13 Well location

All well locations must be approved by the commission, after notification and hearing. No well drilled for solution mining of subsurface minerals shall be located closer than five hundred feet [152.4 meters] from the boundary line of property owned or leased by the operator except by order of the commission. The term boundary line as used herein is understood to mean the boundary of a contiguous set of properties either owned or leased by the operator. 43-02-02-13.1. Exception location.

An operator may apply for an exception to drill at a distance less than five hundred feet [152.4 meters] from the boundary line of a property owned or leased by the operator if the operator submits geological and other technical data to the commission which indicates that waste would occur and that correlative rights will not be violated. 43-02-02-13.2. Deviation tests and directional surveys.

When any well is drilled or deepened, tests to determine the deviation from the vertical shall be taken at least every one thousand feet [304.8 meters]. The director is authorized to waive the deviation test for a shallow gas well if the necessity therefor can be demonstrated to the director's satisfaction.

When the deviation from the vertical exceeds five degrees at any point, the director may require that the hole be straightened. Directional surveys may be required by the director, whenever, in the director's judgement, the location of the bottom of the well is in doubt.

A directional survey shall be made and filed with the state geologist on any well utilizing a whipstock or any method of deviating the well bore. The obligation to run the directional survey may be waived by the director when a well bore is deviated to sidetrack junk in the hole, straighten a crooked hole, control a blowout, or if the necessity therefor can be demonstrated to the director's satisfaction.

The survey contractor shall file with the state geologist free of charge one certified electronic copy of all surveys, in a form approved by the director, within thirty days of attaining total depth. Such survey shall be in reference to true north. The director may require the directional survey to be filed immediately after completion if the survey is needed to conduct the operation of the director's office in a timely manner. Special permits may be obtained from the director to drill directionally in a predetermined direction as provided in this section.

If the director denies a request for a permit to directionally drill, the director shall advise the applicant immediately of the reasons for the denial. The decision of the director may be appealed to the

N.D. Admin. Code 43-02-02-14 Sign on wells

Every well associated with the exploration or mining of subsurface minerals shall be identified by a sign posted on the derrick or not more than twenty feet [6.10 meters] from the well. The sign shall be of durable construction and the lettering thereon shall be kept in a legible condition and shall be large enough to be legible under normal conditions at a distance of fifty feet [15.24 meters]. The wells on each lease or property shall be numbered in nonrepetitive sequence, unless some other system of numbering was adopted by the owner prior to the adoption of this chapter. Each sign must show the well name and number (which shall be different or distinctive for each well), the name of the operator, file number, and the location by quarter-quarter, section, township, and range. 43-02-02-14.1. Site construction.

In the construction of a drill site, access road, and all associated facilities, topsoil shall be removed, stockpiled, and stabilized or otherwise reserved for use when the area is reclaimed. "Topsoil" means the suitable plant growth material on the surface; however, in no event shall this be deemed to be more than the top eight inches [20.32 centimeters] of soil. Soil stabilization additives and materials to be used onsite, access roads or associated facilities must have approval from the director before application.

When necessary to prevent pollution of the land surface and freshwaters, the director may require the drill site to be sloped and diked.

Well sites and associated facilities shall not be located in, or hazardously near, bodies of water, nor shall they block natural drainages. Sites and associated facilities shall be designed to divert surface drainage from entering the site.

Well sites and associated facilities or appropriate parts thereof shall be fenced if required by the director.

Within six months after completion of a well, the portion of the well site not used for well operations shall be reclaimed unless waived by the director. Well sites and all associated facilities shall be stabilized to prevent erosion.

N.D. Admin. Code 43-02-02-15 Pits for drilling fluid and drill cuttings. 43-02-02-15.1. Fencing, screening, and netting of drilling and reserve pits

All open pits and ponds which contain saltwater must be fenced. All pits and ponds which contain oil must be fenced, screened, and netted.

This is not to be construed as requiring the fencing, screening, or netting of a drilling pit or reserve pit used solely for drilling, completing, recompleting, or plugging unless such pit is not reclaimed within ninety days after completion of drilling operations. 43-02-02-15.2. Disposal of waste material.

All waste material associated with exploration or production of a subsurface mineral through deep wells must be properly disposed of in an authorized facility.

All waste material recovered from spills, leaks, and undesirable events shall immediately be disposed of in an authorized facility, although the remediation of such material may be allowed onsite if approved by the director.

This is not to be construed as requiring the offsite disposal of drilling mud or drill cuttings associated with the drilling of a shallow well. However, water remaining in a drilling or reserve pit used in the drilling and completion operations of a deep well is to be removed from the pit and disposed of in an authorized disposal well or used in a manner approved by the director. The disposition or use of the water must be included on the sundry notice (form 4-sm) reporting the plan of reclamation pursuant to sections 43-02-02-15.4 and 43-02-02-15.5. 43-02-02-15.3. Earthen pits and open receptacles.

Except as otherwise provided in sections 43-02-02-15.4 and 43-02-02-15.5, no saltwater, drilling mud, crude oil, waste oil, or other waste shall be stored in earthen pits or open receptacles except in an emergency and upon approval by the director.

A lined earthen pit or open receptacle may be temporarily used to retain oil, water, cement, solids, or fluids generated in well completion servicing or plugging operations. A pit or receptacle used for this

purpose must be sufficiently impermeable to provide adequate temporary containment of the oil, water, or fluids. The contents of the pit or receptacle must be removed within seventy-two hours after operations have ceased and must be disposed of at an authorized facility in accordance with section 43-02-02-15.2. Within thirty days after operations have ceased, the earthen pit shall be reclaimed and the open receptacle shall be removed. The director may grant an extension of the thirty-day time period for no more than one year for good cause.

The director may permit pits or receptacles used solely for the purpose of flaring casinghead gas. A pit or receptacle used for this purpose must be sufficiently impermeable to provide adequate temporary containment of fluids. Permission for such pit or receptacle shall be conditioned on locating the pit not less than one hundred fifty feet [45.72 meters] from the vicinity of wells and tanks and keeping it free of any saltwater, crude oil, waste oil, or other waste. Saltwater, drilling mud, crude oil, waste oil, or other waste shall be removed from the pit or receptacle within twenty-four hours after being discovered and must be disposed of at an authorized facility in accordance with section 43-02-02-15.2.

The director may permit pits used solely for storage of freshwater used in completion and well servicing operations. Permits for freshwater pits shall be valid for a period of one year but may be reauthorized upon application. Freshwater pits shall be lined and no pit constructed for this purpose shall be wholly or partially constructed of fill dirt unless approved by the director. The director may approve chemical treatment to municipal drinking water standards upon application. The freshwater pit shall have signage on all sides accessible to vehicular traffic clearly identifying the usage as freshwater only. 43-02-02-15.4. Drilling pits.

A pit may be utilized to bury drill cuttings and solids generated during well and completion operations, providing the pit can be constructed, used, and reclaimed in a manner that will prevent pollution of the land surface and freshwaters. In special circumstances, the director may prohibit construction of a cuttings pit or may impose more stringent pit construction and reclamation requirements. Reserve and circulation of mud system through deep well earthen pits are prohibited unless a waiver is granted by the director. All pits shall be inspected by an authorized representative of the director prior to lining and use. Under no circumstances shall pits be used for disposal, dumping, or storage of fluids, wastes, and debris other than drill cuttings and solids recovered while drilling and completing the well.

Drill cuttings and solids must be stabilized in a manner approved by the director prior to placement in a cuttings pit. Any liquid accumulating in the cuttings pit shall be promptly removed. The pit shall be diked in a manner to prevent surface water from running into the pit.

During the drilling of a deep well, a small lined pit can be authorized by the director for the temporary containment of incidental fluids such as trench water and rig wash, if emptied and covered prior to the rig leaving the site.

Pits shall not be located in, or hazardously near, bodies of water, nor shall they block natural drainages. No pit shall be wholly or partially constructed of fill dirt unless approved by the director.

When required by the director, the drilling pit or appropriate parts thereof shall be fenced.

Within thirty days after the completion of drilling a deep well or expiration of a drilling permit, whichever occurs first, drilling pits shall be reclaimed. The director may grant an extension of the thirty day time period of no more than one year for good cause. Prior to reclaiming the pit, the operator or the operator's agent shall file a sundry notice (form 4-sm) with the director and obtain approval of a pit reclamation plan. Verbal approval to reclaim the pit may be given. The notice must include:

1.The name and address of the reclamation contractor;

2.The name and address of the service owner;

3.The location and name of the disposal site for the pit water when applicable; and

4.A description of the proposed work, including details on treatment and disposition of the drilling waste.

Any water or oil accumulated in the pit must be removed prior to reclamation. Drilling waste from a deep well shall be encapsulated in the pit and covered with at least four feet [1.22 meters] of backfill and topsoil. The surface shall be sloped, when practicable, to promote surface drainage away from the reclaimed pit area. 43-02-02-15.5. Reserve pit for drilling mud and drill cuttings from shallow wells.

For wells drilled to a strata or formation, including lignite or coal strata or seam, located above the depth of five thousand feet [1524 meters] below the surface, or located more than five thousand feet [1524 meters] below the surface but above the top of the Rierdon formation, a container or reserve pit of sufficient size to contain said material or fluid, and the accumulation of drill cuttings may be utilized to contain solids and fluids used and generated during well drilling and completion operations, providing the pit can be constructed, used, and reclaimed in a manner that will prevent pollution of the land surface and freshwaters. A reserve pit may be allowed by an order of the commission after notice and hearing for wells drilled within a specified field and pool more than five thousand feet [1524 meters] below the surface and below the top of the Rierdon formation provided the proposed well or wells utilize a low sodium content water-based mud system and the reserve pit can be constructed, used, and reclaimed in a manner that will prevent pollution of the land surface and freshwaters. In special circumstances, based on site conditions, the director or authorized representative may prohibit construction of a reserve pit or may impose more stringent pit construction and reclamation requirements, including reserve pits previously authorized by a commission order within a specified field or pool. Under no circumstances shall reserve pits be used for disposal, dumping, or storage of fluids, wastes, and debris other than drill cuttings and fluids used or recovered while drilling and completing the well.

Reserved pits shall not be located in, or hazardously near, bodies of water, nor shall they block natural drainages. No reserve pit shall be wholly or partially constructed in fill dirt unless approved by the director.

Within thirty days after the completion of a shallow well, or prior to drilling below the surface casing shoe on any other well, the reserve pit shall be reclaimed. The director may grant an extension of the thirty-day time period of no more than one year for good cause. Prior to reclaiming the pit, the operator, or the operator's agent, shall file a sundry notice (form 4-sm) with the director and obtain approval of a pit reclamation plan. Verbal approval to reclaim the pit may be given. The notice must include:

1.The name and address of the reclamation contractor;

2.The name and address of the surface owner;

3.The location and name of the disposal site for the pit water; and

4.A description of the proposed work, including details on treatment and disposition of the drilling waste.

All pit water must be removed prior to reclamation. Drilling waste should be encapsulated in the pit and covered with at least four feet. [1.22 meters] of backfill and topsoil. The surface shall be sloped, when practicable, to promote surface drainage away from the reclaimed pit area.

N.D. Admin. Code 43-02-02-16 Sealing off strata

During the drilling and operation of any well for subsurface minerals, all mineral-bearing and water strata above the producing horizon shall be sealed or separated where necessary in order to prevent their contents from passing into other strata.

All freshwaters and waters of present or probable value for domestic, commercial, or stock purposes shall be confined to their respective strata and shall be adequately protected by methods approved by the commission. Special precautions shall be taken in drilling and plugging wells to guard against any loss of artesian water from the strata in which it occurs, and the contamination of artesian water by objectionable water or subsurface minerals.

All water shall be shut off and excluded from the various subsurface mineral-bearing strata which are penetrated. Water shutoffs shall ordinarily be made by cementing casing or landing casing with or without the use of mud-laden fluid.

N.D. Admin. Code 43-02-02-17 Casing and tubing requirements

All wells drilled for subsurface minerals below the base of the Fox Hills formation shall be completed with strings of casing which shall be properly cemented at sufficient depths to adequately protect and isolate all formations containing water, subsurface minerals, oil, or gas or any combination of these; protect the pipe through salt sections encountered; and isolate the uppermost sand of the Dakota group.

Drilling of the surface hole shall be with freshwater-based drilling mud or other method approved by the director which will protect all freshwater-bearing strata. The surface casing shall consist of new or reconditioned pipe that has been previously tested to one thousand pounds per square inch [6900 kilopascals]. The surface casing shall be set and cemented at a point not less than fifty feet [15.24 meters] below the base of the Fox Hills formation. Sufficient cement shall be used on surface casing to fill the annular space behind the casing to the bottom of the cellar, if any, or to the surface of the ground. If the annulus space is not adequately filled with cement, the director shall be notified immediately. The operator shall diligently perform work after obtaining approval from the director. All strings of surface casing shall stand cemented under pressure for at least twelve hours before drilling the plug or initiating tests. The term "under pressure" as used herein shall be complied with if one float valve is used or if pressure is otherwise held. Cementing shall be by the pump and plug method or other methods approved by the director. The director is authorized to require an accurate gauge be maintained on the surface casing of any well, not properly plugged and abandoned, to detect any buildup of pressure caused by the migration of fluids.

Surface casing strings must stand under pressure until the tail cement has reached a compressive strength of at least five hundred pounds per square inch [3450 kilopascals]. All filler cements utilized must reach a compressive strength of at least two hundred fifty pounds per square inch [1725 kilopascals] within twenty-four hours and at least three hundred fifty pounds per square inch [2415 kilopascals] within seventy-two hours. All compressive strengths on surface casing cement shall be calculated at a temperature of eighty degrees Fahrenheit [26.67 degrees Celsius].

Unless otherwise specified by the director, production or intermediate casing strings shall consist of new or reconditioned pipe that has been previously tested to two thousand pounds per square inch [13800 kilopascals]. Such strings must stand under pressure until the tail cement has reached a compressive strength of at least five hundred pounds per square inch [3450 kilopascals]. All filler cements utilized must reach a compressive strength of at least two hundred fifty pounds per square inch [1725 kilopascals] within twenty-four hours and at least five hundred pounds per square inch [3450 kilopascals] within a seventy-two hours, although in any horizontal well performing a single-stage cement job from a measured depth of greater than thirteen thousand feet [3962.4 meters], the filler cement utilized must reach a compressive strength of at least two hundred fifty pounds per square inch [1725 kilopascals] within forty-eight hours and at least five hundred pounds per square inch [3450 kilopascals] within ninety-six hours. All compressive strengths on production or intermediate casing cement shall be calculated at a temperature found in the Mowry formation using a gradient of one and two tenths degrees Fahrenheit per one hundred feet [30.48 meters] of depth plus eight degrees Fahrenheit [26.674 degrees Celsius].

After cementing, each casing string shall be tested by application of pump pressure of at least one thousand five hundred pounds per square inch [10350 kilopascals]. If, at the end of thirty minutes, this pressure has dropped one hundred fifty pounds per square inch [1035 kilopascals] or more, the casing shall be repaired after receiving approval from the director. Thereafter, the casing shall again be tested in the same manner. Further work shall not proceed until a satisfactory test has been obtained. The casing in a horizontal well may be tested by use of a mechanical tool set near the casing shoe after the horizontal section has been drilled.

All flowing wells must be equipped with tubing. A tubing packer must also be utilized unless a waiver is obtained by demonstrating the casing will not be subjected to excessive pressure or corrosion. The packer must be set as near the producing interval as practicable, but in all cases must be above the perforations.

N.D. Admin. Code 43-02-02-18 Defective casing or cementing

In any well that appears to have defective casing or cementing, the operator shall report the defect to the state geologist on a sundry notice (form 4-sm). Prior to attempting remedial work on any casing, the operator must obtain approval from the director and proceed with diligence to conduct test, as approved or required by the director, to properly evaluate the condition of the well bore and correct the defect. The director is authorized to require a pressure test to verify casing integrity if its competence is questionable. The director may allow the well bore condition to remain if correlative rights can be protected without endangering potable waters. The well shall be properly plugged if requested by the director.

Any well with open perforations above a packer shall be deemed to have defective casing. 43-02-02-18.1. Perforating, fracturing, and chemically treating wells.

During treatment operations, the director may prescribe pretreatment casing pressure testing as well as other operational requirements designed to protect wellhead and casing strings. If damage results to the casing or the casing seat from perforating, fracturing, or chemically treating a well, the operator shall immediately notify the director and proceed with diligence to use the appropriate method and means for rectifying such damage, pursuant to section 43-02-02-18. If perforating, fracturing, or chemical treating results in irreparable damage which threatens the mechanical integrity of the well, the commission may require the operator to plug the well.

N.D. Admin. Code 43-02-02-19 Blowout prevention

In all drilling operations, proper and necessary precautions shall be taken for keeping the well under control, including the use of a blowout preventer and high-pressure fittings attached to properly cemented casing strings adequate to withstand anticipated pressures. During the course of drilling, the pipe rams shall be functionally operated at least once every twenty-four-hour period. The blind rams shall be functionally operated each trip out of the well bore. The blowout preventer shall be pressure-tested at installation on the wellhead, after modification of any equipment, and every thirty days thereafter. The director may postpone such pressure test if the necessity can be demonstrated to the director's satisfaction. All tests shall be noted in the driller's record.

N.D. Admin. Code 43-02-02-20 Safety regulation

Any rubbish or debris that might constitute a fire hazard shall be removed to a distance of at least one hundred fifty feet [45.72 meters] from the vicinity of wells and tanks. All waste shall be burned or disposed of in such manner as to avoid creating a fire hazard. All vegetation must be removed to a safe distance from any production equipment to eliminate a fire hazard.

The director may require remote operated or automatic shutdown equipment be installed on, or shut in for no more than forty days, any well that is likely to cause a serious threat of pollution or injury to the public health or safety.

No well shall be drilled or production or injection equipment installed less than five hundred feet [152.4 meters] from an occupied dwelling unless agreed to in writing by the owner of the dwelling or authorized by order of the commission.

1.No well (or subsurface mine) site may be placed within four hundred feet [121.92 meters] of the centerline of any state highway, unless otherwise approved by the director of the department of transportation, or the director's designee.

2.If direct access from a state highway to a well (or subsurface mine) site is desired, the mineral resource permit applicant must obtain a driveway permit from the department of transportation district office as required by department of transportation policies in force at the time of the request.

Subsurface pressure must be controlled during all drilling, completion, and well-servicing operations with appropriate fluid weight and pressure control equipment. 43-02-02-20.1. Pulling string of casing.

When removing casing strings from any subsurface mineral or injection well, the space above the casing stub shall be kept and left full of fluid with adequate gel strength and specific gravity, cement, or combination thereof, to seal off all freshwater and saltwater strata and any strata bearing oil or gas not producing. No casing shall be removed without the prior approval of the director.

N.D. Admin. Code 43-02-02-21 Well and lease equipment

Wellhead and lease equipment with a working pressure at least equivalent to the calculated or known pressure to which the equipment may be subjected shall be installed and maintained. Valves shall be installed and maintained in good working order to permit pressure readings to be obtained on both casing and tubing. 43-02-02-21.1. Notification of fires, leaks, spills, or blowouts.

All persons controlling or operating any well, pipeline, receiving tank, storage tank, or production facility into which subsurface minerals or water is produced, received, stored, processed, or through which subsurface minerals or water is injected, piped, or transported, shall verbally notify the director within twenty-four hours after discovery of any fire, leak, spill, blowout, or release of fluid. If any such incident occurs or travels offsite of a facility, the persons, as named above, responsible for proper notification shall within a reasonable time also notify the surface owners upon whose land the incident occurred or traveled. Notification requirements prescribed by this section shall not apply to any leak, spill, or release of fluid that is less than one barrel total volume and remains onsite of a facility. The verbal notification must be followed by a written report within ten days after cleanup of the incident, unless deemed unnecessary by the director. Such report must include the operator and description of the facility, the legal description of the location of the incident, date of occurrence, date of cleanup, amount and type of each fluid involved, amount of each fluid recovered, steps taken to remedy the situation, cause of the accident, and action taken to prevent reoccurrence. The signature, title, and telephone number of the company representative must be included on such report. The persons, as named above, responsible for proper notification, within a reasonable time, also shall provide a copy of the written report to the surface owners upon whose land the incident occurred or traveled.

The commission, however, may impose more stringent spill-reporting requirements if warranted because of proximity to sensitive areas, past spill performance, or careless operating practices as determined by the director. 43-02-02-21.2. Leak and spill cleanup.

At no time shall any spill or leak be allowed to flow over, pool, or rest on the surface of the land or infiltrate soil. Discharge fluids must be properly removed and may not be allowed to remain standing within or outside of diked areas. Operators must respond with appropriate resources to contain and clean up spills.

N.D. Admin. Code 43-02-02-22 Well log, completion, and work-over report and basic data

After the plugging of a well, a plugging records (form 7-sm) shall be filed with the state geologist.

After the completion of a well, recompletion of a well in a different pool, or drilling horizontally in an existing pool, a completion report (form 6-sm) shall be filed with the state geologist. In no case shall subsurface minerals be transported from the lease prior to the filing of a completion report unless approved by the director. The operator shall cause to be run an open hole electrical, radioactivity, or other similar log, or combination of open hole logs, of the operator's choice, from which formation tops and porosity zones can be determined. The operator shall run a gamma ray log from total depth to ground level elevation of the well bore. Prior to completing the well, the operator shall run a log form which the presence and quality of bonding of cement can be determined in every well in which production or intermediate casing has been set. The obligation to log may be waived or postponed by the director if the necessity therefore can be demonstrated to the director's satisfaction. Waiver will be contingent upon such terms and conditions as the director deems appropriate. All logs run shall be available to the director at the well site prior to proceeding with plugging or completion operations. All logs run shall be submitted to the state geologist free of charge. Logs shall be submitted as one digital tagged image file format (TIFF) copy and one digital LAS (log ASCII) formatted copy, or a format approved by the director. In addition, operators shall file two copies of drill stem test reports and charts, formation water analyses, core analyses, geologic reports, and noninterpretive lithologic logs or sample descriptions if compiled by the operator.

All information, except the operator name, well name, location, spacing or drilling unit description, spud date, rig contractor, and any production runs, furnished to the state geologist on recompletions or reentries, shall be kept confidential for a period of one year if requested by the operator and such period may be further extended upon approval by the commission. The one-year period shall commence on the expiration date of the permit. The confidentiality period will become void if the operator engages in a wholesale release of the confidential information in a wide public form. Any information furnished to the state geologist prior to approval of the recompletion or reentry shall remain public.

Approval must be obtained on a sundry notice (form 4-sm) from the director prior to perforating or recompleting a well in a pool other than the pool in which the well is currently permitted.

After the completion of any remedial work, or attempted remedial work, such as plugging back or drilling deeper, acidizing, shooting, formation fracturing, squeezing operations, setting liner, perforating, reperforating, or other similar operations not specifically covered herein, a report on the operation shall be filed on a sundry notice (form 4-sm) with the state geologist. The report shall present a detailed account of all work done and the date of such work; the daily production of subsurface minerals and water both prior to and after the operation; the shots per foot, size, and depth of perforations; the quantity of sand, crude, chemical, or other materials employed in the operation; and any other pertinent information or operations which affect the original status of the well and are not specifically covered herein.

Upon the installation of pumping equipment on a flowing well, or change in type of pumping equipment designed to increase productivity in a well, the operator shall submit a sundry notice (form 4-sm) of such installation. The notice shall include all pertinent information on the pump and its operation, including the date of such installation, and the daily production of the well prior to and after the pump has been installed.

All forms, reports, logs, and other information required by this section shall be submitted within thirty days after the completion of such work, although a completion report shall be filed immediately after the completion or recompletion of a well in a pool or reservoir not then covered by an order of the The following basic data collected by the operator shall be delivered, free of charge, to the state geologist within six months of the expiration date of the permit:

1.Washed and packaged sample cuts, core chips, or whole cores except those portions of cores used for necessary testing or analysis in which case the results of testing, the analysis and the description of missing portions shall be submitted to the state geologist upon request.

2.Sample logs, radioactivity logs, resistivity logs, or other types of electrical or mechanical logs.

3.Elevation and location information on the data collection points.

4.Other pertinent information as may be requested by the director.

When requested by the operator, the data submitted shall be confidential for a period of one year commencing on the expiration date of the permit. Such period may be further extended upon approval of the commission.

Data restricted to a particular stratigraphic interval containing the actual ore being explored, developed, or mined, shall be confidential as long as the operator is exploring, developing, or producing from that particular stratum. The general area, as used herein, shall be defined jointly by the state geologist and the operator. Definition of the stratigraphic interval will be made by the state geologist.

Data from the stratigraphic interval will, at the discretion of the state geologist, be retained in the North Dakota office of the operator during the period of confidentiality. The industrial commission and the state geologist shall have access to all confidential data.

The director may release such confidential completion and production data to health care professionals, emergency responders, and state, federal, or tribal environmental and public health regulators if the state geologist deems it necessary to protect the public's health, safety, and welfare. 43-02-02-22.1. Determination of well potential. 43-02-02-22.2. Subsurface pressure test.

The operator shall conduct a subsurface pressure test on the discovery well of any new pool discovered and shall report the results to the director within thirty days after the completion of such discovery well. Drill stem test pressures are acceptable. After the discovery of a new pool, each operator shall make additional subsurface pressure tests as directed by the director or provided for in field rules. All tests shall be made by a person qualified by both training and experience to make such tests and with an approved subsurface pressure instrument. All wells shall remain completely shut in for at least forty-eight hours prior to the test. The subsurface determination shall be obtained as close as possible to the midpoint of the productive interval of the reservoir. The report of the reservoir pressure test shall be filed on form 9-sm.

The director may shut in any well for failure to make such test until such time as a satisfactory test has been made or satisfactory explanation given. 43-02-02-22.3. Commingling of minerals from pools.

Except as directed by the commission after notice and hearing, each pool shall be produced as a single common reservoir without commingling in the well bore of fluids from different pools. After fluids from different pools have been brought to the surface, such fluids may be commingled provided that the amount of production from each pool is determined by a method approved by the director.

N.D. Admin. Code 43-02-02-23 Notice of intention to plug well

The operator or the operator's agent shall file a notice of intention (form 4-sm) to plug with the state geologist, and obtain the approval of the director, prior to the commencement of plugging or plug-back operations. The notice shall state the name and location of the well, the name of the operator, and the method of plugging, which must include a detailed statement of proposed work. In the case of a recently completed test well that has not had production casing in the hole, the operator may commence plugging by giving reasonable notice to, and securing verbal approval of, the director as to the method of plugging and the time plugging operations are to begin. Within thirty days after the plugging of any well, the owner or operator thereof shall file a plugging record (form 7-sm), and, if requested, a copy of the cementer's trip ticket of job receipt, with the state geologist setting forth in detail the method used in plugging the well. This section shall not apply to testholes.

N.D. Admin. Code 43-02-02-24 Method of plugging

All wells shall be plugged in a manner which will confine permanently all subsurface minerals, oil, gas, and water in the separate strata originally containing them. This operation shall be accomplished by the use of mud-laden fluid, cement, and plugs, used singly or in combination as may be approved by the director. All casing strings shall be cut off at least three feet [91.44 centimeters] below the final surface contour, and a cap shall be welded. Core or stratigraphic testholes drilled to or below sands containing freshwater shall be plugged in accordance with the applicable provisions recited above. After plugging, the site must be reclaimed pursuant to sections 43-02-02-14.1 and 43-02-02-24.2. 43-02-02-24.1. Abandonment of wells - Suspension of drilling.

1.The removal of production equipment or the failure to produce subsurface minerals, or the failure to produce water from the source well, for one year constitutes abandonment of the well. The removal of injection equipment or the failure to use an injection well for one year constitutes abandonment of the well. The failure to plug a stratigraphic testhole of reaching total depth within one year constitutes abandonment of the well. An abandoned well must be plugged and its site must be reclaimed pursuant to sections 43-02-02-24 and 43-02-02-24.2.

2.The director may waive the requirement to plug and reclaim an abandoned well for one year by giving the well temporarily abandoned status. This status may only be given to wells that are to be used for purposes related to the production of subsurface minerals. If a well is given temporarily abandoned status, the well's perforations must be isolated, the integrity of its casing must be proven, and its casing must be sealed at the surface, all in a manner approved by the director. The director may extend a well's temporarily abandoned status beyond one year. A fee of one hundred dollars shall be submitted for each application to extend the temporary abandonment status of any well.

3.In addition to the waiver in subsection 2, the director may also waive the duty to plug and reclaim an abandoned well for good cause as determined by the director. If the director exercises this discretion, the director shall set a date or circumstances upon which the waiver expires.

4.The director may approve suspension of the drilling of a well. If suspension is approved, a plug must be placed at the top of the casing to prevent any foreign matter from getting into the well. When drilling has been suspended for thirty days, the well, unless otherwise authorized by the director, must be plugged and its site reclaimed pursuant to sections 43-02-02-24 and 43-02-02-24.2. 43-02-02-24.2. Reclamation of surface.

1.Within a reasonable time, but not more than one year, after a well is plugged, or if a permit expires, has been canceled or revoked, the well site, access road, and other associated facilities constructed for the well shall be reclaimed as closely as practicable to original condition. Prior to site reclamation, the operator or the operator's agent shall file a sundry notice (form 4-sm) with the director and obtain approval of a reclamation plan. The operator or operator's agent shall provide a copy of the proposed reclamation plant to the surface owner at least ten days prior to commencing the work unless waived by the surface owner. Verbal approval to reclaim the site may be given. The notice must include:

a.The name and address of the reclamation contractor;

b.The name and address of the surface owner and the date when a copy of the proposed reclamation plan was provided to the surface owner;

c.A description of the proposed work, including topsoil redistribution and reclamation plans for the access road and other facilities; and

d.Reseeding plans, if applicable.

The commission will mail a copy of the approved notice to the surface owner.

All production equipment, waste, and debris shall be removed from the site. Flow lines shall be purged in a manner approved by the director. Flow lines shall be removed if buried less than three feet [91.44 centimeters] below final contour.

2.Gravel or other surfacing material shall be removed, stabilized soil shall be remediated, and the well site, access road, and other associated facilities constructed for the well shall be reshaped as near as is practicable to original contour.

3.The stockpiled topsoil shall be evenly distributed over the disturbed area, and where applicable, the area revegetated with native species or according to the reasonable specifications of the appropriate government land manager or surface owner.

4.Within thirty days after completing any reclamation, the operator shall file a sundry notice with the director reporting the work performed.

5.The director, with the consent of the appropriate government land manager or surface owner, may waive the requirement of reclamation of the site and access road after a well is plugged.

N.D. Admin. Code 43-02-02-25 Wells to be used for freshwater. 43-02-02-25.1. Conversion of mineral wells to freshwater wells

Any person desiring to convert a mineral well to a freshwater well shall file an application for approval with the commission. The application must include the following:

1.If the well is to be used for other than individual domestic and livestock use, a conditional water permit issued by the state water commission.

2.An affidavit by the person desiring to obtain approval for the conversion stating that such person has the authority and assumes all liability for the use and plugging of the proposed freshwater well.

3.The procedure which will be followed in converting the mineral well to a freshwater well.

4.If the well is not currently plugged and abandoned, an affidavit must be executed by the operator of the well indicating that the parties responsible for plugging the mineral well have no objection to the conversion of the mineral well to a freshwater well.

If the commission, after notice and hearing, determines that a mineral well may safely be used as a freshwater well, the commission may approve the conversion.

N.D. Admin. Code 43-02-02-26 Liability

The owner and operator of any well, core hole, or stratigraphic testhole, whether cased or uncased, shall be liable and responsible for the plugging and site reclamation in accordance with the rules and regulations of the commission.

N.D. Admin. Code 43-02-02-27 Earthen pits

N.D. Admin. Code 43-02-02-28 Preservation of cores and samples

Sample cuttings of formations, taken at regular intervals in all wells drilled for subsurface minerals or geological information in North Dakota, shall be washed and packaged in standard sample envelopes which in turn must be placed in proper order in a standard sample box; carefully identified as to operator, well name, location, depth of sample, and shall be sent free of cost to the state geologist within thirty days after completion of drilling operations.

The operator of any well drilled for subsurface minerals in North Dakota, during the drilling of or immediately following the completion of any well, shall inform the state geologist or the state geologist's representative of all intervals that are to be cored, or have been cored. All cores taken shall be preserved and forwarded to the state geologist, free of cost, within ninety days after completion of drilling operations, unless specifically exempted by the state geologist. If an exemption is granted, the operator shall advise the state geologist of the final disposition of the core.

This section does not prohibit the operator from taking such samples of the core as the operator may desire for identification and testing. The operator shall furnish the state geologist with the results of identification and testing procedure.

History

• History: Amended effective October 1, 1990; July 1, 2013.

N.D. Admin. Code 43-02-02-29 Mining plan

Before conducting any mining or production operations, the operator shall submit to the state geologist for approval a mining plan which shall show in detail the proposed development or mining operations to be conducted. Mining plans shall be consistent with and responsive to the requirements of not only this chapter but also statutes and rules for the protection of nonmineral resources, and for the reclamation of the surface of the lands affected by the operations. No operations shall be conducted except under an approved plan. Those portions of a mining plan which the director finds to contain information which is proprietary to a specific company's mining methods shall be retained at that company's office located nearest the mining site, and shall be approved by the director and open to inspection by the director and the industrial commission at all times. All portions of the mining plan which provide for the protection of natural resources, other than the mineral being mined, and for the reclamation of the surface shall be filed in the office of the state geologist.

N.D. Admin. Code 43-02-02-30 Report of production

The operator of each and every well or mine shall, on or before the tenth day of the second month succeeding the month in which production occurs, file with the state geologist the amount of production made by each such well or mine upon form 5-sm or approved computer sheets no larger than eight and one-half by eleven inches [21.59 by 27.94 centimeters]. The report shall be signed by both the person responsible for the report and the person witnessing the signature. The printed name and title of both the person signing the report and the person witnessing the signature shall be included. Wells for which reports of production are not received by the close of business on the tenth day of the month may be shut in for a period not to exceed thirty days. The director shall notify, by certified mail, the operator and authorized transporter of the shut-in period for such wells. The term "mine" includes multiple closely spaced wells used to mine a deposit, and in such case production will be reported from the mine rather than from each individual well. "Multiple closely spaced wells" means where more than one well is used to produce subsurface minerals in each eighty-acre [32.37-hectare] subdivision of the mine.

Production data submitted to the state geologist shall be kept confidential for a period of one year when so requested by the operator. Such period may be further extended upon approval by the

N.D. Admin. Code 43-02-02-31 Report of water injected

The operator of each and every injection well shall, on or before the tenth day of the second month succeeding the month in which injection occurs, file with the state geologist the amount of liquid injected, the composition of the liquid, and the source thereof upon approved computer sheets no larger than eight and one-half by eleven inches [21.59 by 27.94 centimeters]. The report shall be signed by both the person responsible for the report and the person witnessing the signature. The printed name and title of both the person signing the report and the person witnessing the signature shall be included.

N.D. Admin. Code 43-02-02-32 Pollution by saltwater

All saltwater liquids or brines produced shall be processed, stored, and disposed of without pollution of freshwater supplies. At no time shall saltwater liquids or brines be allowed to flow over the surface of the land or into streams.

N.D. Admin. Code 43-02-02-33 Investigative powers

Upon receipt of a written complaint from any surface owner or lessee, royalty owner, mineral owner, local, state, or federal official, alleging a violation of the subsurface mineral conservation statutes or any

rule, regulation, or order of the commission, the director shall within reasonable time reply in writing to the person who submitted the complaint stating that an investigation of such complaint will be made or the reason such investigation will not be made. The person who submitted the complaint may appeal the decision of the director to the commission. The director may also conduct such investigations on the director's own initiative or at the direction of the commission. If, after such investigation, the director affirms that cause for complaint exists, the director shall report the results of the investigation to the person who submitted the complaint, if any, to the person who was the subject of the complaint and to the commission. The commission shall institute such legal proceedings as, in its discretion, it believes necessary to enjoin further violations.

N.D. Admin. Code 43-02-02-34 Additional information may be required

This chapter shall not be taken or construed to limit or restrict the authority of the commission to require the furnishing of such additional reports, data, or other information relative to production or products as may appear to be necessary or desirable, either generally or specifically, for the prevention of waste, protection of correlative rights, and the conservation of natural resources.

N.D. Admin. Code 43-02-02-35 Books and records to be kept to substantiate reports

All producers within North Dakota shall make and keep appropriate books and records for a period not less than six years, covering their operations in North Dakota from which they may be able to make and substantiate the reports required by this chapter.

N.D. Admin. Code 43-02-02-36 Public hearing

N.D. Admin. Code 43-02-02-37 Institute proceedings

N.D. Admin. Code 43-02-02-38 Application for hearing

In any proceeding instituted upon application, the application shall be signed by the applicant or by the applicant's attorney. An application shall state (1) the name and general description of the common source or sources of supply affected by the order, rule, or regulation sought, if any, unless same is intended to apply to and affect the entire state, in which event the application shall so state, and such statement shall constitute sufficient description; and (2) briefly the general nature of the order, rule, or

regulation sought in the proceedings.

History

• History: Amended effective August 1, 1986.

N.D. Admin. Code 43-02-02-39 Filing application for hearing

When an application is filed, it shall be set for hearing before the commission at such time as will permit fifteen days' notice thereof to be given, as provided in section 43-02-02-40.

N.D. Admin. Code 43-02-02-40 Hearings - Complaint proceedings - Emergency proceedings - Other proceedings

1.Except as more specifically provided in North Dakota Century Code section 38-12-04, the rules of procedure established in subsection 1 of North Dakota Century Code section 28-32-21 apply to proceedings involving a complaint and a specific-named respondent.

2.For proceedings that do not involve a complaint and a specific-named respondent, the commission shall give at least fifteen days' notice (except in an emergency) of the time and place of hearing thereon by one publication of such notice in a newspaper of general circulation in Bismarck, North Dakota, and in a newspaper of general circulation in the county where the land affected or some part thereof is situated, unless in some particular proceeding a longer period of time or a different method of publication is required by law, in which event such period of time and method of publication shall prevail. The notice shall issue in the name of the commission and shall conform to the other requirements provided by law.

3.In case an emergency is found to exist by the commission which in its judgement requires the making of a rule or order without first having a hearing, the emergency rule or order shall have the same validity as if a hearing with respect to the same had been held after notice. The emergency rule or order permitted by this section shall remain in force no longer than fifteen days from its effective date, and in any event, it shall expire when the rule or order made after due notice and hearing with respect to the subject matter of such emergency rule or order becomes effective.

4.Any person moving for a continuance of a hearing, and who is granted a continuance, shall submit a twenty-five dollar fee to the commission to pay the cost of republication of notice of the hearing. 43-02-02-40.1. Investigatory hearings.

The commission may hold investigatory hearings upon the institution of a proceeding by application or by a motion of the commission. Notice of the hearing must be served upon all parties personally or by certified mail at least five days before the hearing. 43-02-02-40.2. Official record.

The evidence in each case heard by the commission, unless specifically excluded by the hearing officer, includes the certified directional surveys and all subsurface mineral, oil, water, and gas production records on file with the commission.

Any interested party may submit written comments on or objections to the application prior to the hearing date. Such submissions must be received no later than five p.m. on the last business day prior to the hearing date and may be part of the record in the case if allowed by the hearing examiner.

Neither petitions for review of a recommended order nor oral arguments following issuance of a recommended order and pending issuance of a final order are allowed. 43-02-02-40.4. Notice of order by mail.

The commission may give notice of an order by mailing the order, and findings and conclusions upon which it is based, to all parties by regular mail provided it files an affidavit of service by mail indicating upon whom the order was served. 43-02-02-40.5. Service and filing.

All pleadings, notices, written motions, requests, petitions, briefs, and correspondence to the commission or commission employees from a party (or vice versa) relating to a proceeding after its commencement, must be filed with the director and entered into the commission's official record of the procedure provided the record is open at the time of receipt. All parties shall receive copies upon request of any or all of the evidence in the record of the proceedings. The commission may charge for the actual cost of providing copies of evidence in the record. Unless otherwise provided by law, filing shall be complete when the material is entered into the record of the proceeding.

History

• General Authority: NDCC 28-32-06
• Law Implemented: NDCC 28-32-06 43-02-02-40.3. Petitions for review of recommended order and oral arguments prohibited.

N.D. Admin. Code 43-02-02-41 Application for rehearing

Within thirty days after the entry of any order or decision of the commission or the director, any person affected thereby may file with the commission an application for rehearing in respect of any matter determined by the order or decision, setting forth the reasons the order or decision is believed to be erroneous. The commission shall grant or refuse any such application in whole or in part within fifteen days after it is filed. In the event the rehearing is granted, the commission may enter such new order or decision after rehearing as may be required under the circumstances.

N.D. Admin. Code 43-02-02-42 Burden of proof

N.D. Admin. Code 43-02-02-43 Designation of examiners

The commission may by motion designate and appoint qualified individuals to serve as examiners.

The commission may refer any matter or proceeding to any legally designated and appointed examiner or examiners.

N.D. Admin. Code 43-02-02-44 Matters to be heard by examiner

N.D. Admin. Code 43-02-02-45 Powers and duties of examiner

The commission may, by motion, limit the powers and duties of any examiner in any particular case to such issues or to the performance of such acts as the commission deems expedient; however, subject only to such limitation as may be ordered by the commission, the examiner or examiners to whom any matter or proceeding is referred under this chapter shall have full authority to hold hearings on such matter or proceeding in accordance with and pursuant to this chapter. The examiner shall have the power to regulate all proceedings before the examiner and to perform all acts and take all measures necessary or proper for the efficient and orderly conduct of such hearing, including ruling on prehearing motions, the swearing of witnesses, receiving of testimony and exhibits offered in evidence, subject to such objections as may be imposed, and shall cause a complete record of the proceedings to be made and retained.

N.D. Admin. Code 43-02-02-46 Matters heard by commission

N.D. Admin. Code 43-02-02-47 Examiner shall be disinterested umpire

N.D. Admin. Code 43-02-02-48 Report of examiner

Upon the conclusion of any hearing before an examiner, the examiner shall promptly consider the proceedings in such hearings, and based upon the record of such hearing, the examiner shall prepare a report and recommendations for the disposition of the matter or proceeding by the commission. The report and recommendations shall either be accompanied by a proposed order or shall be in the form of a proposed order, and shall be submitted to the commission.

History

• History: Amended effective August 1, 1986.

N.D. Admin. Code 43-02-02-49 Commission order from examiner hearing

After receipt of the report and recommendation of the examiner, the commission shall enter its order disposing of the matter or proceeding.

N.D. Admin. Code 43-02-02-50 Hearing de novo before commission

N.D. Admin. Code 43-02-02-51 Prehearing motion practice

In a matter pending before the commission, all prehearing motions must be served by the moving party upon all parties affected by the motion. Service must be upon a party unless a party is represented by an attorney, in which case service must be upon the attorney. Service must be made by delivering a copy of the motion and all supporting papers in conformance with one of the means of service provided for in rule 5(b) of the North Dakota Rules of Civil Procedure. Proof of service must be made as provided in rule 4 of the North Dakota Rules of Civil Procedure or by certificate of an attorney showing that service has been made. Proof of service must accompany the filing of a motion. Any motion filed without proof of service is not properly before the commission.

Chapter 43-02-02.1 Underground Injection Control Program

N.D. Admin. Code 43-02-02.1 Underground Injection Control Program

CHAPTER 43-02-02.1

UNDERGROUND INJECTION CONTROL PROGRAM

Section 43-02-02.1-01Definitions 43-02-02.1-02Classification of Class III Injection Wells 43-02-02.1-03Powers and Duties 43-02-02.1-04Prohibition of Unauthorized Injection 43-02-02.1-05Prohibition of Movement of Fluid into Underground Sources of Drinking Water 43-02-02.1-06Identification of Underground Sources of Drinking Water and Exempted Aquifers 43-02-02.1-07Permitting 43-02-02.1-08Area Permits 43-02-02.1-09Draft Permits and Fact Sheets 43-02-02.1-10Public Notice and Comment - Requests for Hearings - Public Hearings - Response to Comments 43-02-02.1-11Permit Conditions 43-02-02.1-12Technical Requirements 43-02-02.1-13Plugging and Abandonment 43-02-02.1-14Mechanical Integrity 43-02-02.1-15Area of Review 43-02-02.1-16Schedules of Compliance 43-02-02.1-17Confidentiality of Information 43-02-02.1-18Authorization by Rule 43-02-02.1-19Penalties 43-02-02.1-01. Definitions.

1."Abandoned well" means a well whose use has been permanently discontinued or which is in a state of disrepair such that it cannot be used for its intended purpose or for observation purposes.

2."Aquifer" means a geological formation, group of formations, or part of a formation that is capable of yielding a significant amount of water to a well or spring.

3."Area of review" is used as defined in 40 CFR 146.06.

4."CFR" means Code of Federal Regulations as of April 1, 1983.

5."Commission" means the industrial commission of this state.

6."Contaminant" means any physical, chemical, biological, or radiological substance or matter in water.

7."Draft permit" is used as defined in 40 CFR 144.3.

8."Exempted aquifer" is used as defined in 40 CFR 146.04.

9."Injection well" means a well into which fluids are being injected.

10."Mechanical integrity" is used as defined in 40 CFR 146.08.

11."Person" means an individual, association, partnership, corporation, municipality, state or federal agency, or an agent or employee thereof.

12."Underground source of drinking water" is used as defined in 40 CFR 146.03.

13."Well" means a bored, drilled, or driven shaft, or a dug hole, whose depth is greater than the largest surface dimension. 43-02-02.1-02. Classification of Class III injection wells.

This classification refers to wells which inject for extraction of minerals or energy, including:

1.Mining or sulfur by the Frasch process.

2.In situ production of uranium or other metals. This category includes only in situ production from ore bodies which have not been conventionally mined. Solution mining of conventional mines such as stopes leaching is included in Class V.

3.Solution mining of salts or potash. 43-02-02.1-03. Powers and duties.

The state geologist shall act as a supervisor charged with the duty of enforcing the regulations and orders of the commission applicable to the underground injection control program for Class III disposal wells. All applications, correspondence, protests, and other communications shall be addressed to the state geologist as follows:

State Geologist University Station Grand Forks, ND 58202-8156 (701) 777-2231 43-02-02.1-04. Prohibition of unauthorized injection.

Any Class III underground injection is prohibited except as authorized by permit issued under this

section. Also, the construction of any well required to have a permit under this section is prohibited until the permit has been issued. 43-02-02.1-05. Prohibition of movement of fluid into underground sources of drinking water.

No owner or operator may construct, operate, maintain, convert, plug, abandon, or conduct any other underground injection activity in a manner which causes or allows movement of fluid containing any contaminant into underground sources of drinking water or which may adversely affect the health of persons. The applicant for a permit has the burden of proof of showing that the requirements of this

section are met. 43-02-02.1-06. Identification of underground sources of drinking water and exempted aquifers.

The commission acting by and through the state geologist shall identify underground sources of drinking water and exempted aquifers in accordance with 40 CFR 144.7. 43-02-02.1-07. Permitting.

1.Application for a permit.

a.Any person who is required to have a permit shall complete, sign, and submit an application to the state geologist.

b.When the owner and operator are different, it is the operator's duty to obtain a permit.

c.Applicants shall keep records of all data used to complete permit applications and supplemental information for at least three years.

d.Operators of existing Class III injection wells shall submit a completed application on forms provided by the state geologist no later than four years after approval of the state program.

e.Operators of new injection wells, unless covered by an existing area permit, shall submit an application within a reasonable time before construction is expected to begin.

2.Signatories to permit applications. Permit applications must be signed in accordance with the specifications in 40 CFR 144.32.

3.Duration of permits. Underground injection control permits for Class III wells are effective for a fixed term of not more than ten years.

4.Transfer of permits. Transfer of a Class III permit to a new permittee must be made in accordance with 40 CFR 144.38.

5.Modification, revocation and reissuance, or termination of permits. The commission shall modify, revoke and reissue, or terminate permits as specified in 40 CFR 144.39, 144.40, 144.41, and 124.5, at the request of any affected person or at the commission's initiative. All requests must be in writing and must contain information supportive to the request. 43-02-02.1-08. Area permits.

The commission may issue a permit on an area basis, rather than for each well individually, in accordance with the specifications outlined in 40 CFR 144.33. 43-02-02.1-09. Draft permits and fact sheets.

1.Draft permits. When an application is completed, the commission, acting by and through the state geologist, shall either prepare a draft permit or deny the application. A draft permit must contain all permit requirements.

2.Fact sheets.

a.A fact sheet must be prepared for each draft permit for a major facility or activity, and in those cases which the commission or the state geologist finds that the draft permit is the subject of widespread public interest or raises major issues.

b.If a fact sheet is required, it must be sent to the applicant and, on request, to any other person, and must include the items specified in 40 CFR 124.8. 43-02-02.1-10. Public notice and comment - Requests for hearings - Public hearings - Response to comments.

1.Public notice.

a.The commission shall give public notice that the following actions have occurred:

(1)A draft permit has been prepared;

(2)A hearing has been scheduled; or (3)Intent to deny a permit application.

b.Public notice must be given to allow thirty days for public comment on the draft permit.

c.Public notice of a public hearing must be given at least thirty days before the hearing.

d.Public notice must be given by the methods specified in 40 CFR 124.10(c).

e.Public notices and public notices for hearings must at a minimum contain the information specified in 40 CFR 124.10(d).

2.Public comment.

a.During the public comment period, any interested person may submit written or oral comments and, if no public hearing is scheduled, request a public hearing in writing, stating the nature of the issues.

b.All comments must be considered in making the final decision and must be answered when the final permit decision is made.

3.Public hearing. The commission shall hold a public hearing whenever there is a significant degree of public interest in a draft permit. The commission also may hold a public hearing at its discretion.

4.Response to comments.

a.The commission, acting by and through the state geologist, shall issue a response to comments when a final permit decision is made. The response must:

(1)Specify with provisions, if any, of the draft permit have been changed in the final permit decision, and the reasons for the change; and (2)Briefly describe and respond to all significant comments on the draft permit raised during the public comment period, or during any hearing.

b.The response to comments must be available to the public.

General Authority: NDCC 38-12-04

Law Implemented: NDCC 38-12-04 43-02-02.1-11. Permit conditions.

All permits must contain the conditions specified in 40 CFR 144.51 and 144.52. 43-02-02.1-12. Technical requirements.

1.Construction requirements.

a.General.

(1)Existing wells must achieve compliance with construction requirements prior to permitting or according to a compliance schedule established as a permit condition.

(2)New injection wells must be in compliance with construction requirements prior to commencing injection operations.

(3)Changes in construction plans require approval of the commission, acting by and through the state geologist.

b.Class III construction must conform to the requirements contained in 40 CFR 146.32.

2.Corrective action.

a.All permits must contain the corrective action requirements specified in 40 CFR 144.55.

b.The state geologist's review of the plan for corrective action shall consider the criteria and factors specified in 40 CFR 146.07.

3.Minimum requirements for operating, monitoring, and reporting on Class III wells are included in 40 CFR 146.33.

4.In authorizing a new Class III well, the commission, acting by and through the state geologist, shall require the submission of all the information specified in 40 CFR 146.34.

5.Prior to granting approval for the operation of a well, the commission, acting by and through the state geologist, shall consider the information listed in 40 CFR 146.34(b). 43-02-02.1-13. Plugging and abandonment.

1.Any Class III permit must include conditions to ensure the well will be plugged and abandoned so that movement of fluids is not allowed either into an underground source of drinking water or between underground sources of drinking water.

2.Any underground injection control permit must include a plan for plugging and abandonment which shall be incorporated into the permit as a condition.

3.Temporary intermittent cessation of injection operations is not considered abandonments.

4.Prior to granting approval for plugging and abandonment, the state geologist shall consider the information listed in 40 CFR 146.34(c). 43-02-02.1-14. Mechanical integrity.

A permit for any Class III well or injection project which lacks mechanical integrity must include a condition prohibiting injection operations until the state geologist is satisfied that the specifications for mechanical integrity listed in 40 CFR 146.08 have been met.

Law Implemented: NDCC 38-12-01 43-02-02.1-15. Area of review.

The area of review for each injection well or each field, project, or area of the state must be determined according to 40 CFR 146.06.

General Authority: NDCC 38-12-01 43-02-02.1-16. Schedules of compliance.

1.The compliance schedule must require compliance as soon as possible, and not later than three years, after the effective date of the permit.

2.If the compliance schedule is set for a duration of more than one year, interim requirements and completion dates (not to exceed one year) must be incorporated into the compliance schedule and permit.

3.No later than thirty days following each interim and final date, the permittee shall notify the state geologist in writing of compliance/noncompliance. 43-02-02.1-17. Confidentiality of information.

The following information cannot be claimed confidential:

1.Name and address of permit applicant or permittee.

2.Information which deals with the existence, absence, or level of contaminants in drinking water. 43-02-02.1-18. Authorization by rule.

The commission, acting by and through the state geologist, may authorize Class III underground injection by rule as outlined in 40 CFR 144.21, 144.25, and 144.26. 43-02-02.1-19. Penalties.

Any person who violates any provision of this chapter or any permit conditions is subject to the penalties prescribed in North Dakota Century Code sections 38-08-16 and 38-08-17.

General Authority: NDCC 38-12-05

Law Implemented: NDCC 38-12-05

Chapter 43-02-02.2 In Situ Leach Mineral Mining Rules

N.D. Admin. Code 43-02-02.2 In Situ Leach Mineral Mining Rules

CHAPTER 43-02-02.2

IN SITU LEACH MINERAL MINING RULES

Section 43-02-02.2-01Definitions 43-02-02.2-02Scope of Chapter 43-02-02.2-03Permit Required 43-02-02.2-04Submission of Permit Application 43-02-02.2-05Review for Completeness 43-02-02.2-06Review Period 43-02-02.2-07Permit Application and Annual Operating Fees 43-02-02.2-08Notice of Hearing 43-02-02.2-09Information Added After Filing Date 43-02-02.2-10Notice to Agencies 43-02-02.2-11Summary Document 43-02-02.2-12Permit Approval or Denial 43-02-02.2-13Bond 43-02-02.2-14Permit Application - General Requirements 43-02-02.2-15Permit Application - General Contents 43-02-02.2-16Permit Application - Additional Baseline Information 43-02-02.2-17Permit Application - Mine Operations Plan 43-02-02.2-18Permit Application - Reclamation Plan 43-02-02.2-19Determination of Ground Water Restoration Demonstration 43-02-02.2-20Ground Water Restoration Values 43-02-02.2-21Establishing Baseline Water Quality and Control Parameters in New Mining Areas 43-02-02.2-22Technical Revisions to an In Situ Leach Mine Permit 43-02-02.2-23Designation of Exempted Aquifers 43-02-02.2-24Injection Wells Subject to This Chapter 43-02-02.2-25Well Location and Protection 43-02-02.2-26Well Construction Requirements - General 43-02-02.2-27Well Construction Requirements - Injection Wells 43-02-02.2-28Monitoring Wells - Minimum Requirements 43-02-02.2-29Disposal of Drill Cuttings 43-02-02.2-30Mechanical Integrity 43-02-02.2-31Supervision of Well Construction and Testing 43-02-02.2-32Requirements for Plugging Drill Holes and Repair, Conversion, and Plugging Wells 43-02-02.2-33Corrective Actions for Improperly Sealed Wells 43-02-02.2-34Authorizing New Injection Wells Within Permit Area Boundary 43-02-02.2-35Design and Construction of Surface Facilities 43-02-02.2-36Construction Quality Assurance Plan 43-02-02.2-37Pipeline Design and Construction Requirements 43-02-02.2-38Radioactive Element Recovery Plant and Satellite Facility Design and Construction Requirements 43-02-02.2-39Radioactive Element Byproduct Material Handling and Disposal Systems 43-02-02.2-40Disposal of Liquid Waste 43-02-02.2-41Disposal of Nonradioactive Solid Waste 43-02-02.2-42Prohibitions - Injection Volumes and Pressure 43-02-02.2-43Production Area Operational Monitoring Requirements 43-02-02.2-44Production Area Monitoring Well Location and Spacing Requirements 43-02-02.2-45Nonproduction Zone Monitoring 43-02-02.2-46Subsidence Monitoring 43-02-02.2-47Confinement of Recovery Fluid 43-02-02.2-48Excursions - Reporting Requirement 43-02-02.2-49Excursions - Verifying Analysis 43-02-02.2-50Excursions - Sampling Frequency 43-02-02.2-51Excursions - Remedial Action 43-02-02.2-52Excursions - Controlled 43-02-02.2-53Excursions - Not Controlled 43-02-02.2-54Criteria for Determination of Adequacy of Remedial Action Plan 43-02-02.2-55General Reporting Requirements 43-02-02.2-56Well Construction Records 43-02-02.2-57Well Plugging Records 43-02-02.2-58Maintenance and Retention of Records 43-02-02.2-59Ground Water Restoration Requirements 43-02-02.2-60Restoration Sampling Procedure 43-02-02.2-61Restoration Progress Reports 43-02-02.2-62Final Restoration - Restoration Values Achieved 43-02-02.2-63Restoration Values Not Achieved 43-02-02.2-64Closure of Mine Site Following Restoration 43-02-02.2-65Postclosure Plan - Postclosure Bond - Estimated Costs for Postclosure Care 43-02-02.2-66Reclamation of Surface Facilities 43-02-02.2-67Radiation Survey of Surface Facilities at Mine Closure 43-02-02.2-68Radiation Standards for Closure of Surface Facilities 43-02-02.2-69General Postclosure Inspection, Annual Report, and Maintenance Activities 43-02-02.2-70Postclosure Operation of Monitoring Systems 43-02-02.2-71Ground Water Contamination During the Postclosure Period 43-02-02.2-72Approval of the End of the Postclosure Period 43-02-02.2-73Available Information on In Situ Leach Mines 43-02-02.2-74Final Bond Release 43-02-02.2-75Additional Information May Be Required 43-02-02.2-76Application for Hearing 43-02-02.2-77Hearing Participants by Telephone 43-02-02.2-78Hearings - Complaint Proceedings - Emergency Proceedings - Other Proceedings 43-02-02.2-79Investigatory Hearings 43-02-02.2-80Official Notice 43-02-02.2-81Notice of Order by Mail 43-02-02.2-82Record of Proceedings 43-02-02.2-83Designation of Examiners 43-02-02.2-84Powers and Duties of Examiner 43-02-02.2-85Examiner's Recommended Findings, Conclusions, and Proposed Order 43-02-02.2-86Commission Order 43-02-02.2-87Prehearing Motion Practice 43-02-02.2-01. Definitions.

Terms in this chapter have the same meaning as in North Dakota Century Code chapter 38-12, except:

1."Abandoned well" means a well whose use has been permanently discontinued or that is in such a state of disrepair that it cannot be used for its intended purpose or for observation purposes.

2."Background" means the ambient condition that exists as part of the natural environment at a particular location.

3."Baseline" means a premining condition, concentration, quantity, or quality that is set as a specific value or guideline against which future values are compared.

4."Baseline well" means a well from which ground water is analyzed to define baseline water quality in the permit area.

5."Beneficial use" means a practical use of land that has economic or social value and that allows other sustainable uses.

6."Best available technology" means the best technology, treatment techniques, or other means that the department finds, after examination for efficacy under field conditions and not solely under laboratory conditions, that are available, subject to cost considerations. For the purposes of setting maximum contaminant levels for synthetic organic chemicals, any best available technology must be at least as effective as granular activated carbon.

7."Byproduct material" means surface wastes or material resulting from in situ leach mining.

Underground ore bodies depleted by in situ leach mining do not constitute byproduct material.

8."Casing" means a pipe or tubing of appropriate material lowered into a borehole during or after drilling to support the sides of the hole to prevent the walls from caving; to prevent loss of drilling mud into porous ground; and to prevent water, gas, or other fluid from entering or leaving the hole.

9."Catastrophic collapse" means the sudden and complete failure of overlying strata caused by removing underlying materials.

10."Cementing" means the process of mixing and placing cement grout in a hole to prevent the vertical movement of fluids in the hold or the annulus.

11."Class III well" means under the federal underground injection control program promulgated under part C of the Safe Drinking Water Act, 42 U.S.C. 300 et seq. (2003), a well that injects fluids for extraction of minerals, including solution mining of minerals. The term includes any well used in:

a.Mining of sulfur by the Frasch process;

b.In situ leach mining of uranium or other metals (This category includes only in situ production from ore bodies that have not been conventionally mined. Wells used for solution mining, such as stope leaching, are classified as class V wells.); or

c.In situ mining of salts, trona, or potash.

12."Composite liner" means a liner made of two components, typically a geomembrane and a soil liner.

13."Confining zone" means a geological unit that is stratigraphically adjacent to one or more aquifers and restricts the movement of ground water into and out of the aquifer or aquifers it confines.

14."Contaminant" means any physical, chemical, biological, or radiological substance or matter in water, soil, or air that is potentially harmful to human health or the health of animals or plants.

15."Contiguous land" means land bordering the land within the permit area.

16."Control parameter" means a chemical constituent of ground water monitored on a routine

basis and used to detect the presence of recovery fluids in a monitoring well.

17."Department" means the department of mineral resources of the industrial commission.

18."Ephemeral drainage" means a stream or reach of a stream that flows only in direct response to precipitation or to the melting of snow or ice in the immediate watershed.

19."Excursion" means any unauthorized movement of recovery fluid out of the production zone as a result of mining.

20."Exempted aquifer" means an aquifer or portion of an aquifer that meets the criteria in the definition of "underground source of drinking water" but which has been exempted under

section 33.1-25-01-05.

21."Facility" means all contiguous land and all structures and improvements on the permit area used for mining.

22."Filing date" means the date on which the department notifies the applicant that its application is complete.

23."Final reclamation" means reclamation performed that satisfies the requirements of the approved reclamation plan and attains the intended postmining land use.

24."Fluid" means any material or substance that flows or moves whether in a semisolid, liquid, sludge, gas, or other form.

25."Formation" means a body of consolidated or unconsolidated rock characterized by a degree of lithologic homogeneity that is prevailingly, but not necessarily, tabular and is mapable on the earth's surface or traceable in the subsurface.

26."Formation fluid" means fluid present in a formation under natural conditions. It does not include introduced fluids.

27."Geomembrane" means a synthetic, impermeable membrane used in contact with soil or other materials in geotechnical and civil engineering applications to contain liquids. Geomembranes are made of various materials, with each type having different characteristics that affect installation procedures, lifespan, and performance.

28."Geotechnical analysis" means a study of the engineering characteristics and properties of the site's soils, rocks, and other materials for suitability in construction.

29."Ground water" means water below the land surface that is in the zone of saturation.

30."Ground water restoration" means the condition achieved when the quality of ground water affected by injecting mining solution in production and nonproduction zones is returned to restoration values.

31."Grout" means a slurry used to form a permanent, impervious seal in the annular space or to fill and seal abandoned holes or wells.

32."Hazardous waste" has the meaning given in subsection 1 of section 33.1-24-02-03 and North Dakota Century Code section 23-20.3-02.

33."In situ leach mining" means a method of in-place surface mining in which limited quantities of overburden are disturbed to install a conduit or well and minerals are mined by injecting or recovering a liquid, solid, sludge, or gas that causes the leaching, dissolution, gasification, liquefaction, or extraction of minerals. In situ leach mining does not include the primary or enhanced recovery of naturally occurring oil and gas.

34."Injection well" means a class III well.

35."Injection zone" means a geological formation, group of formations, or part of a formation receiving fluids through a well for the purposes of mineral recovery.

36."Intermittent drainage" means a stream or reach of a stream that flows for at least some part of the year and obtains its flow from surface runoff and ground water discharge.

37."Mechanical integrity" means the condition of an injection well, when there is no significant leak in the casing, tubing, or packer, and there is no significant fluid movement into an unauthorized zone or underground source of drinking water through vertical channels adjacent to the injection well bore. The determination that there are no significant leaks or fluid movement is based on the results of mechanical integrity testing.

38."Mining" means in situ leach mining, unless the context requires otherwise.

39."Mining solution" means the injected fluid containing the chemicals used to mobilize the minerals into solution.

40."Monitoring well" means any cased excavation or opening into the ground made by digging, boring, drilling, driving, jetting, or other methods to determine the physical, chemical, biological, or radiological properties of ground water.

41."Negative pressure gradient" means the condition that results from the creation of a localized hydrological cone of depression or pressure sink within the production zone caused by the production of more fluid than was injected. The purpose of this pressure gradient is to contain the recovery fluid by causing natural ground water to move from the surrounding area toward the production zone.

42."Nonproduction zone" means an aquifer that is above or below the production zone.

43."Occupied dwelling" means a residence that is lived in by a person at least six months throughout a calendar year.

44."Operator" means the principal that is on the bond covering the facility.

45."Perennial drainage" means a stream or reach of a stream that flows continuously during all of the calendar year as a result of ground water discharge or surface runoff.

46."Permit amendment" means a change to an approved mining permit that requires department approval.

47."Permit application" means a mining permit application.

48."Permit area" means the area approved by the department in which mining may occur.

49."Plugging" means the process of filling a borehole or a well to restore hydrologic conditions and to prevent migration of ground water between strata.

50."Postmining land use" means the beneficial land use or uses upon which a mining operation reclamation plan is based, including forest planting, agriculture or horticulture, rangeland, wildlife habitat, recreation, residential and industrial sites, and future mineral exploration and development.

51."Pressure" means the total force per unit area acting on a surface.

52."Process solution" means a solution used in extracting minerals from ore during the milling process.

53."Production" means removing or processing at least ten percent of the permitted annual minerals or the conduct of other activities, including reclamation, which significantly move the operation toward completion.

54."Production area" means the area in which mining takes place.

55."Production well" means a well or conduit through which a recovery fluid, mineral, or product is produced from the subsurface. If a well is used for both injection and recovery, it is considered an injection well for the purposes of this chapter until the operator demonstrates to the department that the well has been converted to uses other than injection.

56."Production zone" means the geologic interval into which mining solutions are to be injected and recovery fluids extracted.

57."Radioactive waste" means any waste that contains radioactive material in concentrations that exceed those listed in chapter 33-10-04.1, appendix B, table II, column 2.

58."Receiving strata" means the geologic units within which the production zones are contained.

59."Recovery fluid" means the fluid resulting from injecting mining solution that has dissolved or mobilized minerals from the production zone for extraction and recovery.

60."Restoration table" means a list of parameters in the mining permit with assigned ground water quality restoration values that are the compliance requirements for restoring production and nonproduction zones.

61."Restored aquifer" means that portion of an aquifer within a restoration area where the water quality has, by natural or artificial processes, returned to restoration values.

62."Satellite facility" means a mineral recovery or ion exchange facility set up at a remote distance from a central processing plant.

63."Slope" means the average inclination of a surface measured from the horizontal.

64."Solid waste" has the meaning given in North Dakota Century Code section 23-29-03.

65."Submission" means the initial physical delivery of an application to the department.

66."Surface impoundment" means a natural or artificial closed basin that holds water, slurry, or other liquid or semiliquid material. A permanent surface impoundment is a structure that will remain after final bond release.

67."Tailings impoundment" means a structure designed to hold tailings, including leach pads and dumps containing treated spent ore of the mined mineral.

68."Technical revision" means a change in the operating plan, reclamation plan, or permit that the department determines has only a minimal effect on the interests this chapter seeks to protect or advance.

69."Topsoil" means soil at the earth's surface that will easily produce and sustain vegetation growths specified in an approved reclamation plan.

70."Treatment" means any method or process, including neutralization, designed to change the physical, chemical, or biological character or composition of a waste for the purpose of disposal or final reclamation.

71."Unauthorized zone" means the area outside the production zone that is not permitted for injecting mining solution or extracting recovery fluid, or authorized for any excursion of recovery fluid out of the production zone.

72."Underground source of drinking water" means an aquifer or part of an aquifer that meets any one of the following:

a.Supplies any public water system;

b.Contains a sufficient quantity of ground water to supply a public water system and either currently supplies drinking water for human consumption or contains fewer than ten thousand milligrams per liter total dissolved solids; or

c.Is not an exempted aquifer.

73."Upper limit value" means a chemical or physical concentration greater than the maximum value of a parameter that can be attributed to natural fluctuations and analytical variability.

Upper limit values are determined by the department from the baseline sampling prior to initiation of mining. Upper limit values are used to determine when there is movement of recovery fluid out of authorized areas or unapproved changes to a chemical or physical parameter. For certain parameters, such as pH, an upper limit value may be defined as an acceptable range of values.

74."Verifying analysis" means a second sampling and analysis of control parameters for the

purpose of confirming a routine sample analysis that indicates an increase in a control parameter to a level exceeding the upper limit value.

75."Well" means an artificial excavation or opening in the ground with a depth greater than the largest surface dimension by which ground water is sought or through which ground water flows under natural pressure or is artificially withdrawn. A well is made by digging, boring, drilling, jetting, or another artificial method, and is often walled or cased to prevent the sides from caving.

76."Yellowcake" means a processed oxide of uranium, U O , that is extracted and concentrated from uranium ore. 43-02-02.2-02. Scope of chapter.

This chapter contains general rules adopted to conserve the natural resources of North Dakota and to prevent pollution of freshwater supplies, to provide for the protection of the environment and public safety, to ensure the optimum recovery of the mineral resource, and the reclamation of all land disturbed by operations regulated by this chapter to a condition consistent with prior land use and productive capacity. Special rules and orders will be issued when required and prevail over general rules, and orders if in conflict. The commission may grant exceptions to this chapter, after due notice and hearing, when such exceptions will result in the prevention of waste and operate in a manner to protect correlative rights. 43-02-02.2-03. Permit required.

A permit is required prior to commencement of mining. The commission shall review the facility permit at least once every five years to determine whether the permit should be amended, modified, or revoked. 43-02-02.2-04. Submission of permit application.

Any person who conducts or expects to conduct mining operations shall file with the department a complete permit application and all required materials. The applicant shall file with the department proof that it submitted a copy of the application to the county recorder in the county in which the proposed permit area is located. 43-02-02.2-05. Review for completeness.

The department will determine whether the application is complete. The department will notify the applicant in writing, within thirty days after the application is submitted, whether the application is complete or specify deficiencies that must be corrected in order to complete the application. If the application is substantially deficient, it will be rejected. The department will notify the applicant when the application is considered complete. 43-02-02.2-06. Review period.

1.The department will have one hundred eighty days after the filing date to approve or disapprove the application.

2.The department may extend the review period not to exceed an additional one hundred eighty days if:

a.Additional time is needed to correct application deficiencies.

b.Significant changes are submitted that in the department's judgment require additional time to review. The department may require additional public notification of the amended application.

c.The department requires additional time to conduct an informal conference or a formal hearing or complete the decision. 43-02-02.2-07. Permit application and annual operating fees.

A fee of twenty thousand dollars must accompany the permit application. Permit revisions may require additional fees not to exceed ten thousand dollars.

The annual operating fees must be based upon the costs to monitor and inspect the facility. 43-02-02.2-08. Notice of hearing.

The commission will give thirty days' notice (except in an emergency) to the general public of the time and place of the hearing on the application. Immediately upon receiving notice of the hearing date, the permit applicant shall give notice by certified mail to surface and subsurface owners within the permit application area and to the county recorder in the county or counties in which the proposed permit area is located. 43-02-02.2-09. Information added after filing date.

Additional information submitted to the department by the applicant to supplement, correct, amend, or clarify an application following the filing date must also be submitted with the county recorder in the county or counties in which the proposed permit area is located. The additional information must be submitted at least thirty days before the hearing date. The applicant must transmit proof of submission to the department. The department shall give notice to the public of the additional information at least fifteen days before the scheduled hearing date. 43-02-02.2-10. Notice to agencies.

Within the first ten days of the review period of a permit application, the department shall send copies of the application to the department of agriculture, the state department of health, and to the state water commission. 43-02-02.2-11. Summary document.

The permit application must contain a summary document that describes the main elements of the operation and identifies the major environmental issues involved. 43-02-02.2-12. Permit approval or denial.

Within ninety days of the hearing, or a reasonable time thereafter, the department will notify the applicant of the commission's decision as to whether the permit is approved or denied. 43-02-02.2-13. Bond.

1.Before any person receives a mining permit, the person shall submit to the department and obtain its approval of a surety bond or cash bond. An alternate form of security may be approved by the department. Each such surety bond must be executed by a responsible surety company authorized to transact business in North Dakota.

2.The amount of the bond must be commensurate with size and scope of the mining operation and the cost of abandoning operation and reclamation.

3.The information provided in section 43-02-02.2-18, along with any additional information available to the department, will be used to determine the reclamation costs.

4.The size and the scope of the operation will be evaluated annually and the department may increase or decrease the bond amount to reflect the results of the evaluation. 43-02-02.2-14. Permit application - General requirements.

1.All applications must be submitted in a format satisfactory to the department. The applicant shall provide information that is complete, current, presented clearly and concisely, and supported by appropriate references to technical and other written material. All technical analyses must have been conducted by a qualified individual. The department may require the applicant to supplement the application with information beyond that specifically required by these rules if the department believes that additional information is necessary to make an informed decision.

2.The applicant shall provide four copies of the application to the department and one copy to the county recorder in the county in which the proposed permit area is located. 43-02-02.2-15. Permit application - General contents.

1.The application must:

a.Describe by legal description the land for which a permit is sought.

b.Identify all property interests the applicant holds, including options, in the lands for which a permit is sought and in all contiguous land. This identification must cover surface and subsurface interests and legal descriptions must be provided identifying the location of each interest and option.

c.List the names and addresses of the following:

(1)The permit applicant.

(2)Every legal or equitable owner of record (surface and subsurface) of the property for which a permit is sought.

(3)The holders of record (surface and subsurface) of any leasehold interest in the property.

(4)Any purchaser of record (surface and subsurface) of the property under a contract.

(5)The operator, if the operator is a person different from the permit applicant.

(6)If any of the above are business entities other than a single proprietor, the names and addresses of the principals, officers, and resident agent.

(7)Every owner of record of all surface and subsurface interests in contiguous land.

d.State, if the applicant is a partnership, corporation, limited liability company, association, or other business entity. State that the applicant is registered with the North Dakota secretary of state to do business in North Dakota and state:

(1)The names and addresses of every officer, manager, partner, director, governor, or person performing a function similar to a director.

(2)The name and address of any person owning of record ten percent or more of any class of voting stock or membership interests of the applicant.

e.All names under which the applicant, and any partner, principal shareholder, or principal member of the applicant, was involved in a mining operation within any state during the five years preceding the date of the application.

f.A description of any pending, current, or previous permits for mining operations in any state being sought or held by the applicant and any partner, principal shareholder, or principal member of the applicant.

g.A description of any instance in which the applicant has been formally notified that it violated any law of the United States or the state of North Dakota, or of any agency of the United States or of the state of North Dakota, pertaining to air or water protection in connection with any mining operation during the five years prior to the date of application.

The applicant must also explain the final resolution of any such notice.

h.Whether the applicant, any subsidiary, affiliate, or persons controlled by or under common control with the applicant, has ever held any federal or state permit for a mining operation that in the five years prior to the date of the application has been suspended or revoked, or has had a bond or similar security for a mining operation forfeited and, if so, explain the facts involved.

i.In this subdivision, "mining operations" is interpreted broadly to cover all kinds of mining.

2.The application must provide the names of persons that collected and analyzed data referred to in the application, as well as:

a.Dates of collection and analyses.

b.Descriptions of methodology used.

3.The application must provide the name, address, and position of officials of each private or academic research organization or governmental agency consulted in preparing the application.

4.Maps must accompany the application to aid the department's understanding and analysis of it.

a.Maps must be legible and drawn to a scale that clearly shows the elements being delineated. Permit area map scales must be 1:2,400 or larger. Maps showing lands and water in contiguous areas must be at a scale 1:24,000 or larger. The department may approve requests for map scale changes. Maps must:

(1)Show the name of the applicant;

(2)Be prepared and signed by a person qualified to prepare the map;

(3)Give the date prepared;

(4)Identify the purpose the map fulfills;

(5)Include a legend;

(6)Indicate township, range, and section boundaries; and (7)Identify scale.

b.Base maps are required and must identify all major topographic features and landmarks, streams, towns, subdivisions, historic or archaeologic sites, utilities, roads, and buildings.

In lieu of delineating these items on the map, the use of a standard United States geological survey seven-and-one-half-minute quadrangle map may be used as a base map. Contour (topographic) maps must accurately locate and identify the permit area, the proposed permit boundary, and the location of any public highways, dwellings, utilities, and easements within the permit area and contiguous lands in relation to all proposed affected lands and proposed activities associated with the mining, including all processing facilities, chemical storage areas, production areas, and roads. The map shall also clearly illustrate the location of monitoring wells.

5.The application must describe the activities to be conducted by the applicant for which permits are required from state, federal, and local governments. It must also list all permits or construction approvals received or applied for in association with the proposed mining activity under the following:

a.The hazardous waste management program under article 33.1-24;

b.The underground injection control program under article 33.1-25 and chapter 43-02-02.1 and under North Dakota Century Code chapter 61-28;

c.The control, prevention, and abatement of pollution of surface waters program under

article 33.1-16 and under North Dakota Century Code chapter 61-28;

d.The air quality program under article 33.1-15 and under North Dakota Century Code

chapter 23.1-06;

e.Section 404 of the Clean Water Act;

f.The radiation control program under article 33.1-10 and under North Dakota Century Code chapter 23.1-02, when radioactive elements will be produced in sufficient quantities;

g.A United States nuclear regulatory commission source and byproduct material license, when radioactive elements will be produced in sufficient quantities;

h.Laws administered by the state engineer, state water commission, and water resource districts; and

i.Any other federal, state, and local permits or approvals. 43-02-02.2-16. Permit application - Additional baseline information.

1.Baseline water quality and water level data must be submitted with the application. The data must represent at least a one-year period during which data is collected monthly unless the applicant can demonstrate to the department's satisfaction that less frequent sampling or sampling for a shorter period for specific locations is hydrologically justifiable. In no case may baseline sampling be less frequent than quarterly.

2.The following information is required:

a.Ground water baseline information, including:

(1)A geochemical, lithological, and mineralogical description of the receiving strata and any aquifers that may be affected by injecting mining solution;

(2)Aquifer characteristics for the water-saturated portions of the receiving strata and aquifers that may be affected by the mining process. Characteristics must include aquifer thickness, velocity and direction of ground water movement, potentiometric gradient, storage coefficients or specific yields, transmissivity or hydraulic conductivity, water level data, recharge and discharge areas, and the directions of preferred flow under hydraulic stress in the saturated zones of the receiving strata.

The extent of hydraulic connection between the receiving strata and overlying and underlying aquifers and the hydraulic characteristics of any influencing boundaries in or near the proposed production areas must be determined and described; and (3)The volume and areal extent of ground water anticipated to be influenced by the injection activities. The area of review must include the area within a one-quarter mile [.40 kilometer] radius of the injection wells, or as determined by the department.

b.Geology of the land within the proposed permit area and contiguous lands, including representative geologic cross sections and structure contour maps or three-dimensional fence diagrams of the target mineral deposit.

c.A surface water inventory map on a topographic base map, depicting all identifiable surface water resources potentially affected by the proposed mining process, including seeps, springs, rivers, streams, lakes, ponds, wetlands, and reservoirs. The map must also address surface water quality and quantity, discharge rates, and other information necessary to characterize the hydrologic system.

d.A well location inventory map depicting any identifiable wells and exploration test holes, located within one mile [1.61 kilometers] of the boundary of the permit area accompanied by a table of all known existing water wells, producing wells, injection wells, abandoned wells, and exploration holes, giving location, depth, producing intervals, type of use, condition of casing, plugging procedures and date of completion for each well or drill hole within that same area to the extent such information is available in public records and from a reasonable inspection of the property.

e.A potentiometric surface map of the mining zone and the overlying and underlying hydrostratigraphic units on a topographic base map as well as any near-surface aquifers.

f.A geochemical characterization of the ore rock. The EP toxicity test must be used.

g.A surface and ground water monitoring plan for the life of the mine.

h.Meteorologic data and a meteorologic monitoring plan.

i.A drainage, erosion, and sedimentation control plan.

j.For operations using chemicals in the milling process, a description of the proposed methods to monitor and collect leakage or spills and a spill contingency plan.

k.An estimate of the water requirements, including flow rates and volumes for each phase of the mining and restoration operation. This estimate must include a description of the potential effect on the quality and quantity of the proposed water source.

l.A description of the chemical characteristics of process solutions and the chemicals used to process ore, including a range of operating concentrations.

m.Preliminary engineering plans and specifications for pollution control facilities and a quality control plan for constructing those facilities.

n.Site-specific background radiological data, including the results of measurements of radioactive materials occurring in important species, soil, air, and in surface and ground waters that could be affected by the proposed mining operations, when radioactive elements will be produced in sufficient quantities. The applicant shall develop a preoperational environmental radiological monitoring plan. The plan must include a radiation survey of the proposed mine facilities area to include process or recovery facilities, ponds, impoundments, and wellfields.

o.Identification of unstable or seismic areas.

p.A list and map of all adjudicated and permitted ground water and surface water rights within a six-mile [9.65-kilometer] radius of the mine permit boundary.

q.Land use and zoning laws within the mine permit and within a one-mile [1.61-kilometer] radius of the mine permit boundary.

r.A list of occupied dwellings within the mine permit and within a one-mile [1.61-kilometer] radius of the mine permit boundary.

3.The department may require presubmission meetings to discuss the procedures for baseline data and site characterization. 43-02-02.2-17. Permit application - Mine operations plan.

Applications must include a mining plan, which must include:

1.A narrative description of the mining and milling techniques to be employed, including plan view maps of the proposed mining;

2.A narrative description of the proposed depth and direction of mining including representative maps and cross sections;

3.A map depicting the proposed locations of all buildings and infrastructure, including pipelines, surface impoundments, waste dumps, and other mine-related facilities;

4.Discussion and illustration of the estimated mining schedule, including:

a.A list of the proposed wellfields;

b.A map showing the proposed sequence for mining the wellfields;

c.An estimated time schedule for mining each wellfield; and

d.The capacity of the water and wastewater treatment systems and correlation of their capacity with the mining and restoration schedules;

5.Conceptual plans and specifications for mining facilities in accordance with section 43-02-02.2-35;

6.A plan for ground water monitoring adjacent to ponds and surface impoundments and a leak response plan detailing actions that will be taken in response to detecting leaks from these areas. The plan must be in accordance with United States nuclear regulatory commission requirements when radioactive elements will be produced in sufficient quantities;

7.A plan for the periodic inspection and maintenance of mine facilities to include pipelines and lined impoundments. The plan must include criteria for repair or replacing equipment or infrastructure to keep mine facilities in good repair and order, and a quarterly report to include inspection logs, problems identified, and repair or replacement work completed. The plan must be in accordance with United States nuclear regulatory commission requirements when radioactive elements will be produced in sufficient quantities;

8.The composition of all known and anticipated wastes and procedures for their disposal;

9.Procedures for ensuring that all radioactive, toxic, acid-forming, or other materials constituting a fire, health, safety, or environmental hazard encountered during or created by the mining are promptly treated, confined, or disposed of in a manner designed to prevent pollution of air, surface water, or ground water, degradation of soils or vegetation, or a threat to human or animal health and safety, and according to state law;

10.A site monitoring plan to include:

a.Ground water quality for both production and nonproduction zones;

b.Surface water quality and quantity, including discharge points, streams and lakes, and general direction of flow off the site;

c.Requirements for water quality sampling and analysis to include:

(1)A description of, or reference for, the procedures and methods used for sample collection, preservation, quality control, and detection levels;

(2)The name, address, and telephone number of the laboratory performing the analyses, and the laboratory identification number; and (3)Signatures of the laboratory manager or technician performing the analyses for the prepermit baseline study and permit requirements;

d.Air quality, including process facilities and other enclosed facilities;

e.Soils;

f.Wildlife and aquatics;

g.Subsidence;

h.Vegetation; and

i.Environmental radiological monitoring of surface water, air, soils, and vegetation;

11.A description of the location within the permit area where underground injection is proposed;

12.A description of the proposed method of operation, including:

a.Injection rate, with the average and maximum daily rate and the volume of fluid to be injected;

b.Injection pressures, with average and maximum injection pressures;

c.A description of how a negative pressure gradient will be maintained within the production zone;

d.Proposed well stimulation program;

e.Type of mining solution to be used;

f.Proposed injection procedure; and

g.Expected changes in pressure, native ground water displacement, and direction of movement of mining solution;

13.The following information concerning the production zone:

a.If the receiving strata is naturally a water-bearing formation:

(1)Fluid pressure;

(2)Fracture pressure;

(3)Physical and chemical characteristics of the receiving strata fluids; and (4)Compatibility of injected fluids with formation fluids; and

b.If the receiving strata is not a water-bearing formation, the fracture pressure in the production zone;

14.The procedures to ensure that installing recovery, injection, and monitoring wells will not result in hydraulic communication between the production zone and overlying or underlying stratigraphic horizons;

15.The procedures used to verify that the injection and production wells are in communication with monitoring wells completed in the receiving strata and employed for the purpose of detecting excursions;

16.The well construction method must be stated in the permit application. Descriptions of the construction and completion details for all injection and production wells in accordance with sections 43-02-02.2-25 through 43-02-02.2-27, and for monitoring wells in accordance with sections 43-02-02.2-25, 43-02-02.2-26, and 43-02-02.2-28;

17.A schedule for and description of the procedures to demonstrate and maintain mechanical integrity of all injection and production wells in accordance with section 43-02-02.2-30;

18.A corrective action plan in accordance with section 43-02-02.2-33 for wells that are improperly sealed, completed, or abandoned, consisting of the steps or modifications necessary to prevent movement of fluid into unauthorized zones;

19.A description of the proposed mining solution and the chemical reactions that may occur during mining as a result of injecting the mining solution;

20.A subsidence analysis, using established geotechnical principles, that estimates, based upon the proposed mining operation, the effect of subsidence upon the land surface and overlying aquifers;

21.A spill contingency plan in accordance with section 33.1-16-02.1-01 to include reporting, response, assessment, and remedial actions;

22.A description of measures employed to prevent an excursion, and in the event of an excursion, the plans to report or to verify the excursion, and plans for remedial action in accordance with sections 43-02-02.2-48 through 43-02-02.2-53;

23.An assessment of impacts that mining may reasonably be expected to have on water resources and water rights inside the permit area and on contiguous land, and the steps that will be taken to mitigate these impacts;

24.A well maintenance plan to ensure:

a.Wells are sufficiently covered to protect against entrance of undesirable material into the well;

b.The wells are marked and can be clearly seen;

c.The area surrounding each well is kept clear of brush or debris; and

d.Monitoring equipment is appropriately serviced and maintained so monitoring requirements can be met;

25.To the extent that existing information or data is available, a determination of whether the annulus of existing water wells has been properly sealed and whether former producing wells, former injection wells, former monitoring wells, abandoned wells, and exploration holes in the proposed production area have been appropriately plugged and abandoned, and if not, a plan for replugging these wells;

26.A plan to minimize a mining operation's adverse impacts, including:

a.Design, construction, and location of facilities to minimize impacts to surface water and ground water;

b.Design and location of facilities so they are compatible with surrounding land uses;

c.Control of access;

d.Preventive measures to minimize harmful impacts to wildlife;

e.Minimizing the production of mine waste; and

f.Integrating mine operations planning with the reclamation plan;

27.A plan to ensure that all refuse from the mining operation, including garbage and rubbish, is disposed of in a permitted solid waste facility and that all special and hazardous wastes are handled in accordance with North Dakota Century Code chapters 23.1-04 and 23.1-08; and

28.A plan for drill hole plugging and well repair, plugging, and conversion must be included in the permit application and constitutes a condition of the permit. 43-02-02.2-18. Permit application - Reclamation plan.

Applications must include a reclamation plan that contains the following:

1.Discussion and information necessary to demonstrate that ground water restoration will be achieved, including:

a.A list of the proposed wellfields;

b.A map showing the estimated sequence for restoring the wellfields;

c.A potentiometric map of the ground water surface in the shallowest aquifer, production zone, and adjacent aquifers;

d.The geochemistry of the shallowest aquifer and the production zone and of up-gradient and down-gradient aquifers, to include oxidation-reduction conditions and common ions;

e.The direction and velocity of ground water movement through the producing zone;

f.The proposed methods to restore ground water quality, based on the geochemistry of the production zone and the chemistry of the mining solutions;

g.An estimated time schedule for restoring each wellfield; and

h.Proposed ground water quality restoration values;

2.A plan for well repair, abandonment, plugging, and conversion;

3.A plan for disposing drill cuttings;

4.An estimated time schedule for achieving reclamation, including ground water restoration and surface reclamation to be completed in not more than five years unless such period is extended by the department upon a finding that additional time is necessary to complete the reclamation plan;

5.Procedures for re-establishing any surface water quality and surface drainage that may be impacted by the mining operation;

6.Procedures for permanently disposing of any radioactive, toxic, or acid-forming materials;

7.Procedures for removing and disposing of structures used in conjunction with the mining operation;

8.Procedures for mitigating or controlling the effects of subsidence;

9.The removal and proper disposal of sludges from impoundments;

10.The removal and proper disposal of geomembranes from impoundments; and

11.On department forms, a cost-estimate for each activity needed for full reclamation, as computed in accordance with established engineering and accounting principles, including:

a.The cost of removing and disposing of structures;

b.The cost of regrading, depositing topsoil, and reseeding affected lands;

c.The cost of facilities, materials, and chemicals used for ground water restoration;

d.The cost of ground water restoration in the production zone;

e.The cost of water treatment;

f.The cost of capping, plugging, and sealing all wells;

g.The cost for collecting and analyzing samples from surface and ground water monitoring sites;

h.The cost for disposing of solid or hazardous waste, such as pond sludges or, when applicable, uranium byproduct material handling and disposal systems, including costs for onsite disposal systems; and

i.The cost for personnel working on reclamation-related activities.

A cost analysis for each activity to be conducted in implementing reclamation of the components of the proposed operation must be included. The method for calculating estimated reclamation costs must be described in detail and is subject to department approval. 43-02-02.2-19. Determination of ground water restoration demonstration.

In deciding whether a sufficient demonstration has been made by the operator under subsection 1 of section 43-02-02.2-18, the department shall consider the premining baseline water quality and geochemistry, including up-gradient and down-gradient aquifers and the direction and velocity of ground water movement through the producing zone. 43-02-02.2-20. Ground water restoration values.

1.Based upon the information submitted under subsection 1 of section 43-02-02.2-18 and the determination under section 43-02-02.2-19, the department shall develop a tabulation of assigned ground water quality restoration values that are the compliance requirements for restoring the production and nonproduction zones. The restoration values must be based on premining baseline conditions. If the ground water restoration demonstration under subsection 1 of section 43-02-02.2-18 indicates that the operation will be unable to return affected ground water to baseline conditions by applying best available technology, the department may set the restoration values as follows:

a.To not exceed concentration levels listed in the North Dakota water quality standards (chapter 33-16-02.1) or narrative standards; or

b.To not exceed the health advisory levels or secondary drinking water regulations set by the United States environmental protection agency; and

2.Modifying the restoration values must be done in accordance with section 43-02-02.2-63. 43-02-02.2-21. Establishing baseline water quality and control parameters in new mining areas.

1.Before mining a new area in a production zone, the operator shall submit a baseline ground water quality sampling plan that includes an adequate number of wells and samples to adequately characterize baseline water quality in production and nonproduction zones in and adjacent to the new mining area, including all aquifers potentially affected by the proposed mining operation. Water samples may not be taken until the specific conductivity, temperature, and pH have stabilized. These parameters are considered stabilized when there is less than 0.2 pH unit change and ten percent change in conductivity and temperature for at least three consecutive well volumes. These samples must be analyzed for the following parameters: ammonia, antimony, arsenic, barium, beryllium, bicarbonate, boron, cadmium, calcium, carbonate, chloride, chromium, conductivity, copper, dissolved oxygen, fluoride, gross alpha, gross beta, iron, lead, magnesium, manganese, mercury, molybdenum, nitrate, nitrate + nitrite, pH, potassium, selenium, sodium, sulfate, radium-226 and 228, thallium, total dissolved solids, uranium, vanadium, and zinc, and any other parameter specified by the department.

2.All baseline wells must be sampled at least once every month for a minimum of twelve months before any mining activities may occur. If a well shows results indicating a statistically significant variance for a parameter, whether due to laboratory error or natural fluctuation, the department may require additional samples. Sample results for each well must be submitted to the department.

3.The department shall consider the baseline water quality to determine the control parameter and the upper limit value of a control parameter that, if exceeded, indicates that an injected fluid may be present. 43-02-02.2-22. Technical revisions to an in situ leach mine permit.

The department, through permit conditions, may approve proposed technical revisions to the injection well portion of a permit without requiring a permit amendment. These revisions may include the following:

1.Correcting typographical errors;

2.Modifying monitoring plan reporting requirements;

3.Modifying quantities or types of fluids injected that are within the capacity of the facility as permitted and would not interfere with its operation or its ability to meet permit conditions and would not change its classification;

4.Well construction requirements;

5.Adding wells to the wellfield within the permit area if the requirements of section 43-02-02.2-34 are met;

6.Modifying injection rates and pressures;

7.Modifying a well repair, abandonment, plugging, or conversion plan; and

8.Delaying the plugging requirement of subsection 4 of section 43-02-02.2-32 for an unused well. 43-02-02.2-23. Designation of exempted aquifers.

The department, after notice and hearing, may exempt an aquifer or a portion of an aquifer and designate it as an exempted aquifer for class III underground injection control if it meets the following criteria:

1.It does not currently serve as a source of drinking water; and

2.It cannot now and will not in the future serve as a source of drinking water for any of the following reasons:

a.It produces minerals, hydrocarbons, or geothermal energy, or can be demonstrated to contain minerals or hydrocarbons that, considering their quantity and location, are expected to be produced commercially;

b.It is situated at a depth or location that makes recovery of water for drinking water purposes economically or technologically impractical;

c.It is so contaminated that it would be economically or technologically impractical to render the water fit for drinking; or

d.It is located over an injection well mining area subject to subsidence or catastrophic collapse; or

3.The total dissolved solids content of the ground water is more than three thousand and less than ten thousand milligrams per liter and it is not reasonably expected to be used as a drinking water source. 43-02-02.2-24. Injection wells subject to this chapter.

An injection well for mining must comply with this chapter. 43-02-02.2-25. Well location and protection.

In selecting well locations, protecting wells, and maintaining well covers, the following requirements apply:

1.The top of the casing must end at least twelve inches [30.48 centimeters] above grade. The top of the casing must end at least twenty-four inches [60.96 centimeters] above any known high water conditions of flooding from runoff or ponded water, and the immediate area around the well's collar must slope away from the well to direct surface runoff away from the well;

2.Installing wells in the channels and floodplains of perennial drainages is prohibited;

3.Wells installed in an ephemeral or intermittent drainage may not be located in the channel of the drainage. During well construction and use, steps must be taken to minimize the potential for damage to the channel, to protect the well from damage due to erosion, and to prevent surface water runoff from entering the well;

4.The well opening must be closed with a cover to prevent introducing undesirable material into the well. This cover must be locked unless access to the well opening is controlled through another method;

5.If a well is to be constructed near buildings or power lines, the well must be located at a distance from the buildings and power lines to provide access for repairs, maintenance, sampling, and similar work. A well must clear any projection from any building by three feet [.91 meter] and clear any power line by ten feet [3.05 meters]; and

6.No injection or production well shall be drilled less than five hundred feet [152.40 meters] from an occupied dwelling unless agreed to in writing by the surface owner or authorized by order of the commission. 43-02-02.2-26. Well construction requirements - General.

1.Construction requirements listed in this section apply to all wells installed for activities related to mining.

2.The department may grant a deviation from the requirements through a technical revision, if the operator proves that alternative requirements are reliable, ensure mechanical integrity, and will protect ground water.

3.Injection and production wells must be generally constructed as follows:

a.Annular seals must be installed to protect the casing against corrosion, ensure the casing's structural integrity, stabilize the upper formations, protect against contamination or pollution of the well from the surface, and prevent migration of ground water from one aquifer or water-bearing strata to another in accordance with the following requirements:

(1)The drill hole must have a sufficient annular opening to allow for one and one-half inches [38.1 millimeters] of grout around the casing and couplings as per section 33.1-18-01-06. The department may approve an alternative casing design if it provides an equivalent degree of ground water protection;

(2)Before placing the annular seal, the well bore must be under static conditions and all loose drill cuttings, rock chips, or other obstructions must be removed from the annular space by circulating the borehole with water or drilling mud slurry;

(3)Grout must be placed to fill all voids as required in subsection 10 of section 33.1-18-01-06 using a bottom-up trimmie grouting method. Grout must be injected into the subsurface in a sequence beginning at the bottom of the void and progressing upward in two-foot [.61-meter] increments;

(4)Sealing material must consist of neat cement grout or bentonite grout mixtures meeting the following requirements:

(a)Cement grout must be composed of high sulfate-resistant Portland cement and no more than six gallons [22.71 liters] of clean water for each ninety-four-pound [42.64-kilogram] sack of cement to yield a slurry weight of approximately thirteen pounds per gallon. Cement grout must conform to the requirements of subsection 10 of section 33.1-18-01-06;

(b)Bentonite grout must conform to subsection 10 of section 33.1-18-01-06 requirements. High-solids bentonite clay grout, bentonite chips, or bentonite tablets must be commercially prepared specifically for the purpose of sealing water wells;

(c)The sealing material must be thoroughly mixed before applied so there are no balls, clods, or other features that could reduce the seal's effectiveness;

(d)Special quick-setting cement, cement accelerators, retarders, fluid-loss additives, dispersants, extenders, loss-of-circulation materials, and other additives, including hydrated lime to make the mix more fluid or bentonite to make the mix more fluid and reduce shrinkage, may be used, if approved by the department; and (e)Used drilling mud or drill cuttings from the borehole may not be used as sealing material;

b.Well casing must conform to the requirements in subsections 2 and 3 of section 33.1-18-01-06. The casing must be of sufficient strength and diameter to prevent casing collapse during installation, convey liquid at a specified injection/recovery rate and pressure, and allow for sampling. Casing must be installed to avoid damage to casing sections and joints. All joints in the casing above the perforations or screens must be watertight. Casing must be equipped with centralizers placed at a maximum spacing of one per forty feet [12.19 meters] to ensure even thickness of annular seal and gravel pack; and

c.Well development must be by methods that will not cause damage to the well or cause adverse subsurface conditions that may destroy barriers to the vertical movement of water between water-bearing strata. 43-02-02.2-27. Well construction requirements - Injection wells.

The following construction requirements apply to injection wells and are in addition to the requirements of section 43-02-02.2-26:

1.Appropriate logs and other tests must be maintained and conducted during the drilling and construction of injection wells. A descriptive report prepared by a knowledgeable log analyst interpreting the results of such logs must be submitted to the department. The logs and tests appropriate to each type of injection well must be determined based on the intended function, depth, construction, and other well characteristics, availability of similar data in the area of the drilling site, and the need for additional information that may arise from time to time during the well's construction; and

2.All injection wells must be constructed to prevent the migration of fluids to unauthorized zones. The casing and annular sealing material used in each newly drilled well must be designed for the well's life expectancy. In determining these requirements the following factors must be considered:

a.Depth to the deepest injection zone;

b.Injection pressure, external and internal pressure, axial loading, and related information;

c.Hole size;

d.Size and grade of all casing strings, including well thickness, diameter, nominal weight, length, joint specification, and construction material;

e.Corrosiveness of injected fluids and formation fluids;

f.Lithology of injection zone and confining zones; and

g.Type and grade of cement used to seal the annular space between the outer casing and the borehole. 43-02-02.2-28. Monitoring wells - Minimum requirements.

In determining the number, location, and construction of monitoring wells, and the frequency of sampling from monitoring wells, the following must be considered:

1.Whether any person relies on the underground source of drinking water affected or potentially affected by the injection operation;

2.The proximity of the injection operation to points of withdrawal of drinking water;

3.The local geology and hydrology;

4.The operating pressures and whether a negative pressure gradient is being maintained;

5.The toxicity and volume of the injected fluid, the formation water, and the process byproducts;

6.The spatial distribution of the injection wells. 43-02-02.2-29. Disposal of drill cuttings.

1.The operator may dispose and bury drill cuttings in a pit at the well site, such as the mud pit used to circulate drilling fluids, once the drilling operation is complete, if:

a.The drill cuttings are generated from the well at the well site;

b.The drill cuttings are not contaminated with brines, oil, production fluids, or drilling fluids other than tophole water or fresh water;

c.The pit is backfilled and topsoil replaced, and the site is graded to promote runoff with no depression that would accumulate or pond water on the surface. The stability of the backfilled pit must be compatible with the adjacent land;

d.The surface of the backfilled pit area is revegetated under the approved reclamation plan to stabilize the soil surface; and

e.The surface of the backfilled drill cutting pit will not exceed the limits set by the United States nuclear regulatory commission.

2.If not disposed at the well site, contaminated cuttings must be disposed at an approved facility. 43-02-02.2-30. Mechanical integrity.

1.Injection and production wells must maintain mechanical integrity until the wells are plugged under the approved plugging and abandonment plan.

2.Before putting a new injection well into service, its mechanical integrity must be tested. A schedule and methods for mechanical integrity testing must be included in the permit, and are permit conditions. The schedule and methods must meet the following requirements:

a.One of the following methods must be used to evaluate the absence of significant leaks in the casing, tubing, or packer:

(1)Following an initial pressure test, the tubing casing annulus pressure must be monitored with sufficient frequency to be representative, as determined by the department, while maintaining an annulus pressure different from atmospheric pressure measured at the surface;

(2)Pressure test with liquid or gas; or (3)An alternative method if specified in the permit or is approved by the department through a technical revision.

b.The absence of significant fluid movement into any unauthorized zone through vertical channels adjacent to the injection bore must be shown by the results of a temperature, neutron, or noise log, e.g., cement bond log. If the nature of the casing precludes using a log, then sealing records may be used to prove that the sealing material will prevent significant fluid movement. If sealing records are used, the monitoring program must be designed to verify the absence of significant fluid movement.

c.Mechanical integrity of each injection well that has not been plugged or converted must be demonstrated at least once every five years or on a schedule determined by the department.

d.Before resuming injection into any injection well that has been damaged by surface or subsurface activity or that has undergone an activity that may jeopardize its mechanical integrity, such as the use of downhole cutting and under reaming tools, the operator must demonstrate the well's mechanical integrity.

e.If the department determines that an injection well lacks mechanical integrity, it must give written notice of this determination to the well's operator. Unless the department requires immediate cessation, the operator shall cease injection into the well within forty-eight hours upon receipt of the notice. The department will either require the plugging of the well or require the operator to perform such work as is necessary to prevent the movement of fluid into unauthorized zones. Well repair or plugging must be completed within one hundred twenty days upon receipt of the notice. If the well is repaired rather than plugged, retesting of the well must be completed within one hundred twenty days after the repair is completed. The operator may resume injection upon the department's written approval.

f.Results of mechanical integrity testing must be reported under the requirements of

section 43-02-02.2-55. 43-02-02.2-31. Supervision of well construction and testing.

All phases of well construction and testing must be done under the supervision of a water well or monitoring well contractor pursuant to chapter 33.1-18-01 and North Dakota Century Code chapter 43-35. 43-02-02.2-32. Requirements for plugging drill holes and repair, conversion, and plugging wells.

The requirements for plugging drill holes and repairing, converting, and plugging wells are as follows:

1.All drill holes must be plugged under subsection 19 of section 33.1-18-01-06 requirements, as applicable, in a manner that will not allow fluids to move either into or between water-bearing strata;

2.The operator shall notify the department forty-five days before plugging a well within a production area or converting a well to other than injection well uses;

3.All abandoned wells must be plugged or converted, in accordance with the permit's plugging or conversion plan, to ensure that ground water is protected and preserved for future use and to eliminate any potential physical hazard. A well is considered abandoned if it has not been used for two years, unless the operator submits to the department and receives approval for a technical revision demonstrating the operator's intention to use the well again and the actions and specifying procedures that will be taken to ensure that the well's mechanical integrity is maintained and the well will not endanger any unauthorized zone, underground source of drinking water, or water-bearing strata;

4.All wells completed in confined aquifers or encountering more than one aquifer must be plugged in accordance with subsection 19 of section 33.1-18-01-06;

5.All wells completed in unconfined aquifers or with only one aquifer encountered must be plugged in accordance with subsection 19 of section 33.1-18-01-06;

6.To ensure that the locations of abandoned wells are identified:

a.The boundaries of each wellfield and the location of all monitoring wells around the wellfield must be described in an affidavit and the affidavit must be filed with the appropriate county recorder; and

b.The top of the plugging mixture in each abandoned well must clearly show on a steelplate placed atop the sealing mixture the permit number and the well identification number. All steelplates must be installed at a minimum depth of two feet [.61 meter] below the land surface; and

7.Plugging and conversion activities must be reported in accordance with subdivision d of subsection 3 of section 43-02-02.2-55. 43-02-02.2-33. Corrective actions for improperly sealed wells.

1.Improperly sealed, completed, or abandoned wells must be corrected. The operator shall submit a plan, for department approval, that sets forth actions to be taken to prevent movement of fluid between or into water-bearing strata, including underground sources of drinking water, and otherwise into unauthorized zones. The plan must provide information on each well to be remedied, including whether it is a production, monitoring, or abandoned well; the well name or number; and a description of the well's condition.

2.In determining the adequacy of corrective plans, the department shall consider the following:

a.Nature and volume of injected fluid;

b.Nature of native fluids or byproducts of injection;

c.Geology;

d.Hydrology;

e.History of the injection operation;

f.Completion and plugging records;

g.Abandonment procedures in effect at the time the well was abandoned; and

h.Hydraulic connections between water-bearing strata, including underground sources of drinking water. 43-02-02.2-34. Authorizing new injection wells within permit area boundary.

The department may approve proposed technical revisions under section 43-02-02.2-22 to allow the operator to construct and operate new injection wells within the permit area if:

1.The wells meet the construction requirements; and

2.The cumulative effect of drilling and operating additional injection wells is considered and accepted by the department. 43-02-02.2-35. Design and construction of surface facilities.

1.The operator shall submit plans and specifications to the department before constructing the following surface facilities:

a.Process or recovery plants and satellite facilities;

b.Ponds and impoundments;

c.Pipelines;

d.Well houses or transfer stations;

e.Fuel storage areas;

f.Byproduct disposal areas; and

g.Any other facility that may contain substances that could impact human health or degrade the environment if spilled, discharged, or released.

2.Facilities must be designed and operated to comply with the United States nuclear regulatory commission licensing requirements and regulations of the department of environmental quality. 43-02-02.2-36. Construction quality assurance plan.

1.The operator shall develop, for the department's approval, a construction quality assurance plan that addresses all aspects of constructing surface facilities. The plan must include the

a.A description of the responsibilities and authorities of key personnel, including the level of experience and training;

b.A description of the required level of experience, training, and duties of the contractor, the contractor's employees, and the quality assurance inspectors;

c.A description of the testing protocols for every major phase of construction, including the frequency of inspections, field testing, and sampling for laboratory testing;

d.The sampling and field testing procedures and the equipment to be used;

e.The calibration of field testing equipment;

f.The laboratory procedures to be used; and

g.Documentation to be maintained.

2.The operator shall submit the construction quality assurance plan at the same time the plans and specifications required in section 43-02-02.2-35 are submitted. 43-02-02.2-37. Pipeline design and construction requirements.

1.Pipeline systems must be constructed with materials that have the strength, thickness, and chemical properties that prevent failure due to pressure gradients, physical contact with the waste or fluids to which the pipes are exposed, climatic conditions, stress of installation, seismic, and stress of daily operation.

2.Design and construction requirements for wellfield pipelines and pipelines between the wellfield and processing and satellite facilities must include an early detection and shutdown capability in the event of pressure drop or loss of flow. This may include automatic motor-operated valves with pressure transmitters and manually operated valves or devices.

3.Alternative pipeline designs may be used if they provide an equivalent degree of protection to surface and ground water. Pipelines, for facilities that produce radioactive elements, must be designed and constructed in accordance with United States nuclear regulatory commission requirements. 43-02-02.2-38. Radioactive element recovery plant and satellite facility design and construction requirements.

Radioactive element mine recovery plants and satellite facilities must be designed and constructed in accordance with United States nuclear regulatory commission requirements. 43-02-02.2-39. Radioactive element byproduct material handling and disposal systems.

Radioactive solids must be disposed of in accordance with article 33.1-10, United States nuclear regulatory commission source and byproduct material license requirements, and North Dakota Century Code chapters 23.1-02 and 38-23. 43-02-02.2-40. Disposal of liquid waste.

All liquid waste streams must be:

1.Collected and retained in lined evaporation ponds or impoundments constructed in accordance with chapter 33.1-20-08.1;

2.Disposed of in a permitted class I or V underground injection control disposal well under a department of environmental quality underground injection control program permit in accordance with chapter 33.1-25-01;

3.Land applied under a solid waste permit in accordance with chapter 33.1-20-09; or

4.Treated if necessary and discharged under a North Dakota pollution discharge elimination system surface water discharge permit in accordance with chapter 33.1-16-01. 43-02-02.2-41. Disposal of nonradioactive solid waste.

All nonradioactive solid waste must be disposed of offsite at a permitted solid waste facility or may be disposed of onsite if disposal occurs in a solid waste facility permitted according to the North Dakota solid waste rules in article 33.1-20. In addition, the demolition and disposal of any structure must comply with the asbestos requirements in section 33.1-15-13-02. 43-02-02.2-42. Prohibitions - Injection volumes and pressure.

The permit must include maximum injection volume and pressure limits that may not be exceeded, except during well stimulation, to ensure that fractures are not created in the confining zone or zones, injected fluids do not migrate into any unauthorized zone or underground source of drinking water, and formation fluids are not displaced into any unauthorized zone or underground source of drinking water.

Operating requirements must specify that injection pressure be calculated at the wellhead. Injection between the outermost casing protecting unauthorized zones and the well bore is prohibited. 43-02-02.2-43. Production area operational monitoring requirements.

The permit's monitoring plan must describe the procedures for monitoring the quantity and quality of mining solution and ground water in the production area and must include provisions for:

1.The analysis of the physical and chemical characteristics of the injected fluid, with sufficient frequency, and at least monthly, to yield representative data. Manifold monitoring may be used in cases of facilities consisting of more than one injection well operating with a common manifold. Separate monitoring systems for each well are not required provided the operator demonstrates to the department that manifold monitoring is comparable to individual well monitoring;

2.Monitoring injection pressure and either flow rate or volume every two weeks, or metering and recording daily injected and produced fluid volumes;

3.Monitoring the fluid level in the injection zone every two weeks;

4.Monitoring wells in the injection zone shall be sampled every two weeks for chloride, total dissolved solids, alkalinity, conductivity, and any additional parameters requested by the department;

5.Monitoring ground water quality, including the control parameters, and fluid levels in monitoring wells completed above and below the production zone a minimum of every two weeks; and

6.A minimum of quarterly monitoring of department-specified wells within one-quarter mile [.40 kilometer] of the production site to detect migration of recovery fluids from the production zone. 43-02-02.2-44. Production area monitoring well location and spacing requirements.

Production area monitoring wells may be located no more than three hundred feet [91.44 meters] from the production area and with spacing no greater than four hundred feet [121.92 meters] between monitoring wells. Alternative monitoring well locations and spacing may be considered if the operator demonstrates that the proposal will adequately provide monitoring coverage to detect excursions in a timely manner. The department may require closer well spacing in the down gradient ground water flow direction from the production zone. 43-02-02.2-45. Nonproduction zone monitoring.

The majority of monitoring wells in nonproduction zones must be located in the down gradient direction of ground water flow in the aquifer in which the wells are completed. In addition:

1.Nonproduction zone monitoring wells must be completed in any aquifer potentially affected by injection into the production zone. These monitoring wells must be located in two general localities:

a.Inside the production area; and

b.Within a radius of no more than three hundred feet [91.44 meters] from the edge of the production area.

2.Monitoring wells will be spaced:

a.A minimum of one well for every one acre of production area must be completed for the first overlying aquifer above the production zone;

b.A minimum of one well for every three acres of production area must be completed for each additional overlying aquifer; and

c.Based upon a monitoring well spacing plan approved by the department for each underlying aquifer potentially affected by injection.

3.Alternative nonproduction zone monitoring well locations may be considered if the operator demonstrates that the proposal will adequately provide monitoring coverage. 43-02-02.2-46. Subsidence monitoring.

Subsidence must be controlled to ensure that the values and uses of the aquifers and the surface resources will not be degraded. If the injection wells penetrate an aquifer in an area subject to subsidence or catastrophic collapse, an adequate number of monitoring wells must be completed into that aquifer to detect any movement of injected fluids. The monitoring wells must be located outside the physical influence of the subsidence or collapse. 43-02-02.2-47. Confinement of recovery fluid.

Recovery fluid must be restricted to those production zones that have been classified by the department as an exempted aquifer within the area of production. If recovery fluids migrate outside the production zone or into aquifers above or below the production zone, the operator shall report, monitor, and remediate the excursion in accordance with sections 43-02-02.2-48 through 43-02-02.2-53.

Recovery fluids are assumed to be present in an unauthorized zone if a verifying analysis confirms that a control parameter in a monitoring well is detected at a concentration equal to or greater than the upper limit value. 43-02-02.2-48. Excursions - Reporting requirement.

The operator shall report any suspected excursion to the department within twenty-four hours of detection and initiate actions required by section 43-02-02.2-49. The operator shall provide monitoring data or other information that indicates any contaminant may cause adverse impacts to an unauthorized zone or underground source of drinking water. The operator shall report within twenty-four hours any noncompliance with a permit or malfunction of the injection system that may cause fluid migration into or between unauthorized zones. 43-02-02.2-49. Excursions - Verifying analysis.

1.If a routine sample analysis ("initial sampling") indicates a control parameter is exceeding its upper level value in a monitoring well, the operator shall complete a verifying analysis ("second sampling") of samples taken from the affected well and the monitoring wells adjacent to the affected well. The operator shall take the second sampling within two working days after being notified by the laboratory of the initial sampling results. If the results from the first and second sampling event both indicate an excursion has occurred, then an excursion is considered verified for the purpose of initiating remedial action in accordance with section 43-02-02.2-51. If the results of the second sampling are not complete within seven days after the initial sampling event that indicated an excursion might be present, the excursion will be considered verified.

2.If the results from the first and second sampling events provide conflicting information about whether or not an excursion has occurred, then a third sampling event must be conducted within two working days after receipt of the results from the second sampling event. If the results of the third sampling are not complete within seven days after the second sampling event, the excursion will be considered verified.

3.All sample analyses results for excursion events must be submitted to the department within two business days after the operator receives them. 43-02-02.2-50. Excursions - Sampling frequency.

Throughout the time when any control parameter is present in a monitoring well, a water sample must be taken at least two times a week from the well. The samples must be analyzed for all control parameters within one week after the sample is taken. 43-02-02.2-51. Excursions - Remedial action.

1.If the verifying analysis indicates that an excursion has occurred, the operator shall submit to the department for review and approval a remedial plan and a ground water analysis report to include the following:

a.A description of the excursion and its cause;

b.The period of excursion, including exact dates and times;

c.If the excursion has not been corrected, the time it is expected to continue;

d.Steps taken or planned to reduce and prevent recurrence of the excursion; and

e.Sample analyses for pH, calcium, magnesium, sodium, potassium, carbonate, bicarbonate, sulfate, chloride, silica, uranium, ammonia, nitrate, total dissolved solids (one hundred eighty degrees Celsius), specific conductance, and any other parameter specified by the department. One or more of these parameters may be excluded if the department determines that the concentration or value of a specific parameter is not likely to occur as a result of the mining operation.

2.The operator shall submit a remedial action report every two weeks. All reports must be mailed to the department, postmarked within two days after the end of each report period. The first report period begins the day the presence of a control parameter exceeding its upper limit value in a monitoring well is verified. The operator shall continue to submit remedial action reports until cleanup is accomplished. The operator may use any method the operator judges necessary and prudent to define the extent of the excursion and to clean up recovery fluids in an expeditious manner. 43-02-02.2-52. Excursions - Controlled.

1.An excursion is controlled if it can be demonstrated through water quality and ground water gradients or, if applicable, pressure measurements, that recovery fluid in unauthorized areas is declining.

2.If the excursion is controlled, but the control parameters have not been restored to values consistent with local baseline water quality within sixty days following confirmation of the excursion, the operator shall submit, within ninety days following confirmation of the excursion, a plan, for approval by the department, to bring the well or wells off excursion. The plan can be submitted as part of the remedial action report required every two weeks in section 43-02-02.2-51.

3.Cleanup is considered accomplished if the water quality in the affected monitoring wells has been restored to values consistent with local baseline water quality and the restoration is confirmed by three consecutive weekly samples. The department may determine that cleanup is not necessary if the operator demonstrates that the change in water quality is not due to the presence of recovery fluids. 43-02-02.2-53. Excursions - Not controlled.

1.If an excursion is not controlled within thirty days following its confirmation, a sample must be collected from each of the affected monitoring wells and analyzed for the following: ammonia, antimony, arsenic, barium, beryllium, bicarbonate, boron, cadmium, calcium, carbonate, chloride, chromium, conductivity, copper, fluoride, gross alpha, gross beta, iron, lead, magnesium, manganese, mercury, molybdenum, nitrate, nitrate + nitrite, pH, potassium, selenium, sodium, sulfate, radium-226 and 228, thallium, total dissolved solids, uranium, vanadium, and zinc, and any other parameter specified by the department, unless the department determines that the concentration or value of one or more parameters is not likely to occur as a result of the mining.

2.If an excursion is not controlled within sixty days following its confirmation, the department may require the operator to conduct additional sampling of monitoring wells, install additional monitoring wells, terminate injection in the portion of the wellfield in which the excursion originated, or a combination of approaches to assure control within a timely manner. 43-02-02.2-54. Criteria for determination of adequacy of remedial action plan.

In determining the adequacy of the remedial action plan required in section 43-02-02.2-51 proposed by the operator and in determining the additional steps needed to prevent an excursion into unauthorized zones or underground sources of drinking water, the department shall consider the

1.Toxicity and volume of the injected fluid;

2.Toxicity of formation fluids or byproducts of injection;

3.Whether or not any person, animal, wildlife, aquatic life, and plant life is potentially affected by the injection;

4.Geohydrology;

5.History of the injection operation;

6.Completion and plugging records;

7.Abandonment procedures in effect at the time the well was abandoned; and

8.Hydraulic connections with underground sources of drinking water. 43-02-02.2-55. General reporting requirements.

The operator's reporting requirements are as follows:

1.A qualitative analysis and ranges in concentrations of all constituents of injected fluids at least once within the first year of authorization and thereafter whenever the mining solution is modified to the extent that the initial data are incorrect or incomplete. The data so submitted are confidential for one year when requested by the operator and this period of confidentiality can be extended upon approval by the commission;

2.All chemical analyses submitted to the department in accordance with the permit must include the requirements of subdivision c of subsection 10 of section 43-02-02.2-17;

3.Quarterly monitoring reports must include:

a.The results of any periodic tests required by the permit or a remedial plan performed during the reported quarter;

b.The results of all mechanical integrity testing conducted during the reported quarter, including the following information identified by injection well:

(1)Date of mechanical integrity testing;

(2)Identification of the method by which mechanical integrity was established; and (3)Verification that mechanical integrity was or was not established for a well, and if any well failed mechanical integrity testing a description of the method of plugging or repair;

c.The status of corrective action on defective wells, required under section 43-02-02.2-33;

d.The results of well repair and plugging required under section 43-02-02.2-32, including a statement that the wells were plugged in accordance with the permit, or documentation that prior approval was obtained from the department if plugging procedures differed from the procedures approved in the permit. This documentation must be included in the report and contain a description of the procedures used specifying the differences between the approved method and the alternate method. To ensure the well is plugged and there has been no bridging of the sealing material, the operator must provide the department with documentation that the volume of material placed in the well at least equals the volume of the empty hole;

4.During excursions, results from excursion-related monitoring must be reported in accordance with the requirements of section 43-02-02.2-51;

5.A map of the permit area showing reclamation and any derivation from the approved operation and reclamation plan; and

6.An annual report that includes:

a.The operator's name, address, and permit number;

b.A map showing the location of all production and monitoring wells installed during the reporting year and showing all new areas where mining is expected to begin during the next year;

c.A map showing where ground water restoration has been achieved, is actively taking place, and is expected to begin during the next year;

d.A description of ground water restoration methods used and an expected timeline to achieve ground water restoration;

e.The total and the reporting year's amount of affected land;

f.The progress of all reclamation work, including the total and the reporting year's amount of land that has undergone final reclamation and that meets the required postmining land use and that does not meet the required postmining land use;

g.The total quantity of mining solution injected and the total quantity of recovery fluid extracted during the reporting year for each wellfield area, including a description of how these quantities were determined;

h.Monitoring program results that have not been previously reported;

i.An updated potentiometric surface map for all aquifers that are or may be affected by the mining operation;

j.Supporting data sufficient to demonstrate ground water restoration;

k.A summary of all excursions for the reporting year, including remediation progress;

l.A brief discussion of the next year's operational plans, including any anticipated technical revisions or amendments that might require department approval; and

m.The mine facilities inspection and maintenance report required by subsection 7 of section 43-02-02.2-17. 43-02-02.2-56. Well construction records.

For all wells constructed for a mining operation, the person constructing the well shall prepare and submit well construction records as required by subsection 12 of section 33.1-18-01-06. The well construction records shall be submitted to the department and to the department of water well contractors within sixty days after well completion. 43-02-02.2-57. Well plugging records.

For any well plugged and abandoned as part of a mining operation, the person performing plugging and abandonment work shall prepare and submit well plugging records as required by subsection 19 of

section 33.1-18-01-06. The plugging records shall be submitted to the department and the state department of health within sixty days after plugging or at the time of the next quarterly report, whichever is sooner. 43-02-02.2-58. Maintenance and retention of records.

The operator shall retain records of all monitoring information at the mine site, including the

1.Laboratory analyses, including a description of or reference for the procedures and methods used for sample collection, preservation, and quality control and the name, address, telephone number, and laboratory identification number of the laboratory performing the analyses;

2.Records of all data used to complete permit and license applications and any supplemental information;

3.Calibration and maintenance records and all original records of continuous monitoring instrumentation, copies of all reports required by the permit, and records of all data used to complete the permit application;

4.The nature and composition of all injected fluids until three years after the completion of any plugging and abandonment procedures; and

5.Information requested by the department for inclusion in the annual report.

These records must be retained for at least three years from the date of the sample, measurement, or report. This period may be extended by the department. The department may require the operator to deliver a complete set of copies of the records to the department when the retention period ends. 43-02-02.2-59. Ground water restoration requirements.

When the mining of a production area is completed, the operator shall notify the department and immediately proceed to reestablish ground water quality in the affected production area to levels consistent with the values in the permit's restoration table. 43-02-02.2-60. Restoration sampling procedure.

After notifying the department that mining in a production area is complete and that ground water restoration has begun, the operator shall sample and complete an analysis of the baseline wells in the mine production area or as directed by the department. The samples and analysis must be done monthly and are to be conducted to assess the restoration values listed in the permit restoration table.

If this analysis indicates that approved restoration values have been achieved, the operator shall submit to the department a written report of the results. After submitting the report, restoration sampling shall be conducted every two months. The department is to receive copies of all analyses. 43-02-02.2-61. Restoration progress reports.

Beginning six months after initiating restoration of a production area, the operator shall provide semiannual progress reports to the department until restoration is accomplished. 43-02-02.2-62. Final restoration - Restoration values achieved.

The operator shall notify the department if the results of six consecutive sample sets taken once every two months show that ground water quality in the production zone meets the restoration values on the restoration table and that the restoration values indicate stable trends. After the department in writing confirms ground water restoration, the operator may request, through a technical revision, that the department modify the site water quality monitoring plan, which may include a reduction in sampling frequency, substances to be measured, and the number of wells to be sampled in the restored production zone. 43-02-02.2-63. Restoration values not achieved.

1.If the restoration values established in the restoration table of the mine permit are not met after application of best available technology, the operator may submit an amendment to establish alternative restoration values. A one thousand dollar amendment application fee must accompany this submittal.

2.To justify alternative values, the amendment must include all available water quality data for the restoration unit, a narrative discussing the restoration techniques used, including a demonstration that best available practicable technology was applied, and the rationale for altering the restoration values.

3.In determining whether the restoration table should be altered for a particular restoration zone, the department shall consider the following:

a.Uses for which the ground water was suitable at baseline quality levels;

b.Actual existing use of the ground water in the area before and during mining;

c.Potential for future use of the ground water at baseline quality and at proposed restoration values;

d.The effort made by the operator to restore the ground water to the restoration values;

e.The availability of existing technology to restore the ground water to the restoration values; and

f.The potential harmful effects of levels of particular parameters.

4.Alternative restoration values must conform to the requirements of section 43-02-02.2-20.

5.The commission will make a decision on the proposed amendment only after notice and hearing. 43-02-02.2-64. Closure of mine site following restoration.

After completing restoration of all permit area aquifers, the operator shall plug wells that will not be used for postclosure monitoring, and reclaim the facilities in accordance with plans in the permit and reclamation plan. When well plugging and surface reclamation are complete, the operator shall notify the department. A final closure inspection and a review of water quality data shall be conducted by the department. The commission shall hold a hearing to determine if the operator has restored the aquifers and reclaimed the surface facilities and affected lands. Upon successful restoration and reclamation by the operator, the postclosure care and maintenance period will begin. 43-02-02.2-65. Postclosure plan - Postclosure bond - Estimated costs for postclosure care.

Prior to the start of the postclosure period, the operator shall submit to the department the estimated costs for postclosure care and maintenance as computed in accordance with established engineering principles. This information will be used to determine the amount of the postclosure bond.

The estimated costs must include:

1.The cost of long-term ground water restoration to ensure continued compliance consistent with the values in the permit's restoration table for both production and nonproduction zones;

2.The cost of operating monitoring systems; and

3.The cost of inspection and maintenance activities to ensure compliance with all reclamation, design, and operating criteria. 43-02-02.2-66. Reclamation of surface facilities.

1.Unless otherwise approved by the department, the reclamation of surface facilities shall include the removal of all buildings, roads, and structures, and the surface restored to its original contour. Tailings impoundments and ponds must be reclaimed and filled in. All grading, backfilling, and topographic reconstruction must control erosion and sedimentation, protect areas outside the affected land from slides or other damage, and minimize the need for long-term maintenance.

2.Pond and impoundment reclamation must meet the following requirements:

a.Pond sludges must be chemically characterized to determine whether further treatment is necessary before disposal. Sludges must be removed for disposal at an offsite permitted solid waste facility or buried and covered onsite in a solid waste facility permitted in accordance with the applicable solid waste rules in article 33.1-20;

b.Geomembranes must be removed from impoundments, unless it is demonstrated to the department's satisfaction that they will serve a useful function consistent with the approved postmining land use. The geomembrane material must be disposed of in a permitted landfill or may be disposed of onsite only if the operator first secures a solid waste permit in compliance with the North Dakota solid waste rules in article 33.1-20;

c.Radioactive waste shall be disposed of in accordance with a United States nuclear regulatory commission source material license. 43-02-02.2-67. Radiation survey of surface facilities at mine closure.

At mine closure, the operator shall comply with all United States nuclear regulatory commission radiation standards in preparing a radiation sampling and survey plan for mines that produced radioactive elements. A copy of that plan must be filed with the department. 43-02-02.2-68. Radiation standards for closure of surface facilities.

The operator of a radioactive element mine shall comply with all United States nuclear regulatory commission radiation standards. Closed surface facilities must be considered suitable for release for unrestricted use if those standards are met. Copies of all radiological analysis performed both within and outside of the mine permit boundary must be filed with the department. 43-02-02.2-69. General postclosure inspection, annual report, and maintenance activities.

During the postclosure period, the operator shall conduct site maintenance and other activities in accordance with the approved postclosure plan, including the following, as applicable:

1.Conduct quarterly inspections of the entire mine site to monitor the following:

a.Condition of vegetation;

b.Erosion and sediment controls;

c.Wellheads;

d.Subsidence;

e.Impoundments;

f.Safety hazards; and

g.Other potential problems;

2.Maintain vegetation and repair damage to vegetation by taking such steps as adding topsoil, seeding, planting, fertilizing, and mulching;

3.Control noxious weeds;

4.Maintain erosion and sediment control structures. If sediment and erosion controls in an area become unnecessary the structures may be removed for aesthetic purposes;

5.Repair leaking wellheads and replug wells as necessary;

6.Maintain and repair impoundments to ensure stability;

7.Monitor areas of subsidence, fencing subsidence areas as necessary, or undertaking slope reduction as necessary;

8.Maintain locking gates, fences, and warning signs to limit access to the site;

9.Remove or dispose of trash and other waste;

10.Maintain fire protection;

11.Provide equipment, tools, and power to conduct maintenance activities; and

12.As required by the department, all maintenance and repair work must be documented in annual postclosure reports submitted to the department. 43-02-02.2-70. Postclosure operation of monitoring systems.

During the postclosure period, the operator shall continue surface and ground water quality monitoring in accordance with the approved postclosure plan or water quality monitoring plan. The results of all water quality monitoring and laboratory analyses must be included in the annual postclosure reports as required by the department. 43-02-02.2-71. Ground water contamination during the postclosure period.

1.Ground water contamination detected during the postclosure period must be confirmed by additional sampling conducted by the operator as required by the department and must be evaluated to determine whether remedial action is required. The remedial action required by the operator depends upon the extent of the contamination, based upon the following:

a.Whether the contamination is a result of the mining operation;

b.The impacts to the health and well-being of the people, animals, wildlife, aquatic life, and plant life affected;

c.The social and economic value of the affected aquifer;

d.The technical means required to, and the cost of, reducing or eliminating the contamination;

e.The effect upon the environment; and

f.The potential impacts to other waters of the state.

2.Based upon the evaluation, the department shall determine whether remedial action is required. If it is, the operator shall submit a remedial action plan. Depending upon the severity of the contamination and its consequences, the remedial actions may range from additional monitoring to a resumption of ground water restoration activity. The postclosure financial assurance must be recalculated to account for the cost of remedial actions. 43-02-02.2-72. Approval of the end of the postclosure period.

The commission will give notice of public hearing to determine if the postclosure period shall end.

The postclosure period ends when the restored aquifer's water quality consistently meets the restoration values on the permit restoration table and care and maintenance for the permit area are equal to ordinary care and maintenance for similar lands outside the permit area. 43-02-02.2-73. Available information on in situ leach mines.

The department will provide on its website quarterly updates on the operational status, compliance status, technical revisions submitted or approved, and other pertinent information regarding an active in situ leach mine permit. 43-02-02.2-74. Final bond release.

All reclamation required by the approved reclamation plan must be completed prior to final bond release. 43-02-02.2-75. Additional information may be required.

The director has the authority to require additional reports, data, or information relative to mining. 43-02-02.2-76. Application for hearing.

In any proceeding instituted upon application, the application must be signed by the applicant or by the applicant's attorney. An application shall state the name and general nature of the order sought.

General Authority: NDCC 28-32-23, 38-12-02

Law Implemented: NDCC 28-32-21 43-02-02.2-77. Hearing participants by telephone.

In any hearing the commission may allow witnesses and interested parties to participate by telephone. The procedure to do so is as follows:

1.An applicant's participation by telephone will be considered if a written request is made at least ten business days before the hearing.

2.An interested party's participation by telephone will only be considered if the party notifies the applicant and the commission in writing at least three business days before the hearing. Such notice must include the subject hearing, the name and telephone number of the interested party, and the name and telephone number of the interested party's attorney or representative that will be present at the hearing.

3.In the event an objection to any person's participation by telephone is received, the hearing examiner may disallow participation by telephone and may reschedule the hearing. The department will notify all parties whether or not the request to participate by telephone is granted or denied.

4.All persons participating by telephone must have an attorney or other representative present at the hearing who shall be responsible for actually telephoning or otherwise connecting the person to the hearing, for providing the commission with any materials requested to be included in the record, and for any other matters necessary for the party to participate by telephone.

5.All parties participating by telephone shall file an affidavit verifying the identity of such party.

The record of any telephonic participation will not be considered evidence in the case unless the affidavit is received by the department prior to an order being issued by the commission.

The commission shall provide a form affidavit. The commission has the discretion to refuse to consider all or any part of the information received from any party participating by telephone.

6.For all hearings allowing participation by telephone, the department shall provide a hearing room equipped with a speaker telephone.

7.The cost of telephonic communication shall be paid by the party requesting its use.

Law Implemented: NDCC 28-32-35 43-02-02.2-78. Hearings - Complaint proceedings - Emergency proceedings - Other proceedings.

1.Except as more specifically provided in North Dakota Century Code section 38-08-11, the rules of procedure established in North Dakota Century Code section 28-32-21, apply to proceedings involving a complaint and a named respondent.

2.For proceedings that do not involve a complaint and a named respondent the commission shall give at least thirty days' notice (except in an emergency) of the time and place of the hearing by one publication of such notice in a newspaper of general circulation in Bismarck and in a newspaper of general circulation in the county or counties where the land affected or some part of it is situated, unless in some particular proceeding a longer period of time or a different method of publication is required by law, in which event such period of time and method of publication will prevail.

3.If in its judgment the commission believes a rule or order must be issued without a hearing, the emergency rule or order has the same validity as if a hearing had been held after notice.

The emergency rule or order remains in force no longer than forty days and expires earlier if withdrawn by the commission.

Within ninety days of the hearing, or a reasonable time thereafter, the department will notify the applicant of the commission's decision.

Law Implemented: NDCC 28-32-21, 28-32-32 43-02-02.2-79. Investigatory hearings.

The commission may hold investigatory hearings. Notice of the hearing must be served upon all parties personally or by certified mail at least five days before the hearing.

Law Implemented: NDCC 28-32-23 43-02-02.2-80. Official notice.

The evidence in each case heard by the commission, unless specifically excluded by the hearing examiner, includes all uranium and mineral production records on file with the commission.

Law Implemented: NDCC 28-32-24, 28-32-35 43-02-02.2-81. Notice of order by mail.

The commission may give notice of an order by mailing the order to all parties by regular mail.

Law Implemented: NDCC 28-32-39 43-02-02.2-82. Record of proceedings.

All pleadings, notices, motions, requests, petitions, briefs, and correspondence between the commission or commission employee and a party relating to a pending proceeding must be filed with the director and entered into the commission's official record of the proceeding. Unless otherwise provided by law, filing is complete when the material is entered into the record of the proceeding.

Law Implemented: NDCC 28-32-31, 38-32-36 43-02-02.2-83. Designation of examiners.

The commission may designate examiners and may refer any matter or proceeding to its examiners.

Law Implemented: NDCC 38-08-04.1 43-02-02.2-84. Powers and duties of examiner.

The commission may by motion limit the powers and duties of any examiner in any particular case to such issues or to the performance of such acts as the commission deems expedient; however, subject only to such limitation, the examiner to whom any matter is referred has full authority to hold hearings in accordance with this chapter. The examiner has the power to regulate all proceedings before the examiner and to perform all acts and take all measures necessary for the efficient and orderly conduct of the hearing, including ruling on prehearing motions, swearing witnesses, receiving testimony and exhibits offered in evidence, ruling on objections, and shall cause a complete record of the proceeding to be made.

Law Implemented: NDCC 38-08-04.1 43-02-02.2-85. Examiner's recommended findings, conclusions, and proposed order.

Upon the conclusion of any hearing before an examiner, the examiner shall promptly consider the proceedings in such hearing, and based upon the hearing record the examiner shall prepare a recommendation for the commission's disposition of the matter. Such recommendations shall be accompanied by a proposed order.

Law Implemented: NDCC 28-32-31 43-02-02.2-86. Commission order.

After receipt and review of the hearing examiner's recommended findings of fact, conclusions of law, and proposed order, the commission shall enter its final order.

Law Implemented: NDCC 28-32-39 43-02-02.2-87. Prehearing motion practice.

In a matter pending before the commission, all prehearing motions must be served by the moving party upon all parties. Service must be upon a party unless a party is represented by an attorney, in which case service must be upon the attorney. Service must be made by delivering a copy of the motion and all supporting papers in conformance with one of the means of service provided for in

rule 5(b) of the North Dakota Rules of Civil Procedure. Proof of service must be made as provided in

rule 4 of the North Dakota Rules of Civil Procedure or by the certificate of an attorney showing that service has been made. Proof of service must accompany the filing of a motion. Any motion filed without proof of service is not properly before the commission.

Law Implemented: NDCC 28-32-23

Chapter 43-02-02.3 Surface Mining (Noncoal)

N.D. Admin. Code 43-02-02.3 Surface Mining (Noncoal)

CHAPTER 43-02-02.3

SURFACE MINING (NONCOAL)

Section 43-02-02.3-01Definitions 43-02-02.3-02Scope of Chapter 43-02-02.3-03Uranium Surface Mining 43-02-02.3-04Radioactive Material 43-02-02.3-05Bond 43-02-02.3-06Designation and Responsibilities of Operator 43-02-02.3-07Permit Required 43-02-02.3-08Submission of Permit Application 43-02-02.3-09Summary Document 43-02-02.3-10Small Mining Operation Permit Requirements 43-02-02.3-11Large Mining Operation Permit Requirements 43-02-02.3-12Review for Completeness 43-02-02.3-13Review Period 43-02-02.3-14Permit Application Fees 43-02-02.3-15Information Added After Filing Date 43-02-02.3-16Notice to Agencies 43-02-02.3-17Notice of Hearing 43-02-02.3-18Permit Approval or Denial 43-02-02.3-19Permit Term 43-02-02.3-20Permit Modifications or Revision 43-02-02.3-21Revocation and Limitation of Permits 43-02-02.3-22Operational Practices 43-02-02.3-23Performance and Reclamation Standards and Requirements 43-02-02.3-24Report of Production 43-02-02.3-25Annual Report 43-02-02.3-26Additional Information May Be Required 43-02-02.3-01. Definitions.

The terms used throughout this chapter have the same meaning as in North Dakota Century Code

chapter 38-12, except:

1."Adjacent area" means land located outside the permit area where air, surface or ground water, fish, wildlife, vegetation, or other resources may be adversely impacted by surface mining and reclamation operations.

2."Certified or registered mail" means any form of service by the United States postal service, federal express, Pitney Bowes, and any other commercial, nationwide delivery service that provides the mailer with a document showing the date of delivery or refusal to accept delivery.

3."Coal" manes a dark-colored compact and earthy organic rock with less than forty percent inorganic components, based on dry material, formed by the accumulation and decomposition of plant material. The term includes consolidated lignite coal, in both oxidized and nonoxidized forms, having less than eight thousand three hundred British thermal units per pound [453.59 grams], moist and mineral matter free, whether or not the material is enriched in radioactive materials.

4."Department" means the department of mineral resources of the industrial commission.

5."Deposit" means an underground concentration containing a common accumulation of subsurface minerals.

6."Director" means the director of the department of mineral resources of the industrial commission.

7."Disturbed area" means the surface area disturbed by mining and reclamation operations.

Areas are classified as "disturbed" until reclamation is complete and the performance bond or other assurance of performance required by North Dakota Century Code chapter 38-12 and this article is released.

8."Diversion" means a channel, embankment, or other manmade structure constructed to divert water from one area to another.

9."Geomembrane" means a synthetic, impermeable membrane used in contact with soil or other materials in geotechnical and civil engineering applications to contain liquids.

10."Impoundment" means a closed basin, naturally formed or artificially built, which is dammed or excavated for the retention of water, sediment, or waste.

11."Large mining operations" means mining operations which have a disturbed area of more than ten acres at any time.

12."Operator" means any person or persons who, duly authorized, is in charge of the development of a lease or the operation of a producing property.

13."Postmining land use" means a beneficial use or multiple uses which will be established on a permit area after completion of a mining project.

14."Small mining operations" means mining operations which have a disturbed area of ten acres or less at any time.

15."Surface mining" means mining conducted on the land surface including open pit, strip, or auger mining; dredging; quarrying; reworking abandoned dumps and tailing; and activities related thereto.

16."Toxic-forming materials" means earth materials or wastes which, if acted upon by air, water, weathering, or microbiological processes, are likely to produce chemical or physical conditions in soils or water that are detrimental to biota or uses of water.

17."Waste" means:

a.Physical waste;

b.Operations which cause or tend to cause unnecessary or excessive surface loss; or

c.Operations that do not recover all of the mineral being mined that is technically and economically possible. 43-02-02.3-02. Scope of chapter.

This chapter contains general rules of statewide application which have been adopted by the industrial commission to conserve the natural resources of North Dakota, to prevent waste, and to provide for operation in a manner as to protect correlative rights of all owners of subsurface minerals.

Special rules and orders have been and will be issued when required and shall prevail as against general rules, regulations, and orders if in conflict therewith. However, wherever this chapter does not conflict with special rules heretofore or hereafter adopted, this chapter will apply in each case. The commission may grant exceptions to this chapter, and due notice and hearing, when such exceptions will result in the prevention of waste and operation in a manner to protect correlative rights. 43-02-02.3-03. Uranium surface mining.

Surface mining activities targeting uranium ore from noncoal source rock are regulated under this

chapter. Surface mining activities targeting uranium ore from uraniferous lignite deposits are not subject to this section and shall be conducted in accordance with North Dakota Century Code chapter 38-14.1 and North Dakota Administrative Code title 69-05.2 and under the regulatory authority of the public service commission. 43-02-02.3-04. Radioactive material.

The handling, storage, transportation, and disposal of radioactive material shall be in accordance with United States nuclear regulatory commission requirements and those of the state department of health as set forth in North Dakota Century Code chapters 23-20.1, 23-20.2, and 23-20.5 and in North Dakota Administrative Code titles 33-10, 22-24, and 23-25. 43-02-02.3-05. Bond.

Before any person receives a permit to explore for or produce subsurface minerals, the person shall submit to the commission and obtain its approval of a surety bond or cash bond. An alternate form of security may be approved by the commission after notice and hearing, as provided by law. The operator of a well or facility shall be the principal on the bond covering the well or facility. Each such surety bond shall be executed by a responsible surety company authorized to transact business in North Dakota.

1.Bond amounts for surface mining facilities. For surface mining facilities, the amount of the bond will be five thousand dollars per acre [.40 hectare]. The applicant may file either the entire bond for the permit term or an incremental bond schedule and bond required for the first scheduled increment. Increments must be of sufficient size and configuration to provide for efficient reclamation operations.

When the operator elects to increment the amount of the bond, the operator shall:

a.Furnish a legal description of each incremental area.

b.Furnish a schedule when each increment will require bond.

c.Furnish the estimated costs for the commission to complete the reclamation plan for the initial increment.

d.Provide the estimated cost to complete the reclamation plan for the next increment at least ninety days prior to the expected starting date of mining.

2.Bond terms. Bonds shall be conditioned upon full compliance with North Dakota Century Code

chapter 38-12, and all administrative rules and orders of the commission, and continues until any of the following occurs:

a.The testholes or wells have been satisfactorily plugged which shall include practical reclamation of the well site and appurtenances thereto, and all logs, plugging records, and other pertinent data required by statute or rules and orders of the commission are filed and approved.

b.The mined lands or lands disturbed by any method of exploration or production of subsurface minerals have been restored and approved by the director.

c.The liability on the bond has been transferred to another bond and such transfer approved by the commission.

3.Transfer of property under bond. Transfer of property does not release the bond. In case of transfer of property or other interest in a well, extraction facility, or surface mining facility, such as producers not ready for plugging, and the principal desires to be released from the bond covering the well or facility, the principal must proceed as follows:

a.The principal must notify the director in writing of all proposed transfers of property at least thirty days before the closing date of the transfer. The director may, for good cause, waive this requirement.

The principal shall submit to commission a form 8-sm reciting that a certain property, or properties, describing each by quarter-quarter, section, township, and range, is to be transferred for the purpose of ownership or operation to a certain transferee, naming such transferee. The date of assignment or transfer must be stated and the form signed by a party duly authorized to sign on behalf of the principal.

On said transfer form the transferee shall recite the following: "The transferee has read the foregoing statement and accepts such transfer and the responsibility of such property under the transferee's one-well bond, surface mining facility bond, or extraction facility bond". Such acceptance must be signed by a party authorized to sign on behalf of the transferee and the transferee's surety.

b.When the commission has approved the transfer and acceptance and accepted it under the transferee's bond, the transferor shall be released from the responsibility of well plugging and site reclamation. If such wells include all the wells within the responsibility of the transferor's bond, such bond will be released by the commission upon written request. Such request must be signed by an officer of the transferor or a person authorized to sign for the transferor. The director may refuse to transfer any well from a bond if the well is in violation of a statute, rule, or order.

c.The transferee (new operator) of any extraction facility, surface mining facility, or injection well shall be responsible for the plugging and site reclamation of any such property. For that purpose, the transferee shall submit a new bond or, in the case of a surety bond, produce the written consent of the surety of the original or prior bond that the latter's responsibility shall continue and attach to such well. The original or prior bond shall not be released as to the plugging and reclamation responsibility of any such transferor until the transferee submits to the commission an acceptable bond to cover such well. All liability on bonds shall continue until the plugging and site reclamation of such property is completed and approved.

4.Bond termination. The commission shall, in writing, advise the principal and any sureties on any bond as to whether the plugging and reclamation is approved. If approved, liability under such bond may be formally terminated upon receipt of a written request by the principal. The request must be signed by an officer of the principal or person authorized to sign for the principal.

5.Director's authority. The director is vested with the power to act for the commission as to all matters within this section, except requests for alternative forms of security, which may only be approved by the commission.

6.The director shall periodically review the amount of bond. The director may require adjustments to the amount of bond to reflect inflationary increases or increases in the anticipated costs of reclamation.

The commission may refuse to accept a bond if the operator or surety company has failed in the past to comply with statutes, rules, or orders relating to the operation of wells; a civil or administrative action brought by the commission is pending against the operator or surety company; or for other good cause. 43-02-02.3-06. Designation and responsibilities of operator.

The principal on the bond covering a surface mining facility is the operator of the mine. The operator is responsible for compliance with all laws relating to the mine site. A dispute over designation of the operator of a mine site may be addressed by the commission. In doing so, the factors the commission may consider include those set forth in subsection 1 of section 43-02-02.3-21. 43-02-02.3-07. Permit required.

A permit is required prior to commencement of mining. 43-02-02.3-08. Submission of permit application.

Any person who conducts or expects to conduct mining operations shall file with the department a complete permit application and all required materials. The applicant shall file with the department proof that it submitted a copy of the application to the county recorder in the county in which the proposed permit area is located. 43-02-02.3-09. Summary document.

The permit application must contain a summary document that describes the main elements of the operation and identifies the major environmental issues involved. 43-02-02.3-10. Small mining operation permit requirements.

Permit applications for small, noncoal, surface and subsurface mining operations shall address the following:

1.Identification of interests to include:

a.The name and address of the operator responsible for the mining operations and reclamation of the site.

b.The name and address of the surface landowners and mineral owners of all land to be affected by the mining operation.

c.The mine name and the mine safety and health administration identification number.

d.Documents evidencing the operator's right to enter the proposed permit area and conduct mining and reclamation, including showing that the surface owner will be compensated for loss of agricultural production.

2.Project location description and maps plotted at a scale to accurately identify locational landmarks and operational details, to include:

a.A legal description of the proposed permit area.

b.The general location as shown on a topographic map which gives the location the following: perennial, intermittent and ephemeral streams; springs and seeps; wetlands, riparian areas, lakes and other water bodies; residences, businesses, and other structures; existing and proposed roads; other access routes; support facilities; cemeteries; burial grounds; cultural resources listed on the national register of historic places; electrical transmission and communication lines; pipelines; and oil, gas, and water wells on and within one-half mile of the permit area.

c.An operations map that identifies:

(1)The area to be disturbed;

(2)The location of any existing or proposed operations, including access roads, drill holes, trenches, pits, cuts, or other planned small mining activities; and (3)Any previous adjacent disturbance for which the operator is not responsible.

3.Operation plan. A brief narrative description of the proposed mining operation. The description must include the following information:

a.A general description of the minerals sought, the methods of extraction, and any processing to be conducted onsite. Any chemicals to be used onsite must be identified.

b.An estimate of depth to ground water and total dissolved solids concentration.

c.Estimated width and length of any new roads to be constructed.

d.An estimate of the total number of surface acres to be disturbed by the mining operation.

e.A discussion of plans for saving and replacing topsoil and subsoil from the areas to be affected.

f.The amount of material, including mineral deposit, overburden, waste rock, or core hole material, to be extracted, moved, or proposed to be moved, relating to the mining operation.

g.The locations proposed to be used for stockpiling topsoil, subsoil, overburden, and any other materials, including the mineral to be mined.

h.A description of the plans for any structures that will be used for managing runoff from the disturbed areas and a discussion of other sediment control measures that will be used.

4.Reclamation plan. A reclamation plan must be submitted with the permit application to provide a general description of how the land surface of the permit area will be restored as nearly as possible to its original condition following closure. This must include a postmine topographic map or postmine cross sections showing how the disturbed area will conform to the adjacent undisturbed lands. The reclamation plan must discuss the postmining land uses for the disturbed lands and include plans for replacing any premine water supplies that are adversely affected by the mining operations. A detailed reclamation plan may be submitted at the time of application or as a permit modification to the general reclamation plan prior to commencing reclamation operations. 43-02-02.3-11. Large mining operation permit requirements.

In addition to information requirements set forth in subsections 1 through 3 of section 43-02-02.3-10, permit applications for large, noncoal, surface and subsurface mining operations and extraction facilities shall address the following:

1.Identification of interests. In addition to the information requirements set forth in subsection 1 of section 43-02-02.3-10, the applicant will provide the following information:

a.A listing of all parties, including addresses, which have an ownership and controlling interest in the operation. Alternatively, the applicant may submit the applicant's most recent 10k form required by the United States securities and exchange commission.

b.A statement of all current or previous mining operations within the United States held during the five years prior to application owned, operated, or controlled by any person identified in subdivision a and the names and addresses of regulatory agencies with jurisdiction over the environmental aspects of those operations that could provide a compliance history for the operations.

c.The name and address of a designated agent for the service of notices and orders from the director.

d.A listing of all federal and state permits required for the operation.

2.A surface facilities map which identifies the locations of buildings; stationary mining/processing equipment; roads; underground utilities; power lines; proposed drainage control structures; the location of topsoil and subsoil storage areas; tailings or processed waste facilities; disposal areas for overburden; and solid and liquid wastes and wastewater discharge treatment and containment facilities.

3.Sampling and analysis plan.

a.The applicant shall submit four copies of a proposed sampling and analysis plan (SAP) to the director for review prior to baseline data collection. The proposed SAP should contain, at a minimum, the following information for each relevant resource:

(1)Sampling objectives;

(2)A list of the data to be collected;

(3)Methods of collection;

(4)General water chemistry and the parameters to be analyzed for;

(5)Maps indicating the proposed sampling locations;

(6)Sampling frequency; and (7)Laboratory and field quality assurance plans.

b.The director shall distribute the proposed SAP to other agencies as determined by the director. The agencies will have thirty days from receipt of the proposed SAP to submit written comments to the director. Any written comments received within thirty days shall be provided to the applicant. The director shall also provide written comments and recommendations to the applicant on the adequacy of the SAP.

c.The applicant may request a conference with the director to discuss the SAP.

4.Baseline data. Descriptions, maps, drawings, or photographs shall be included as required for determination of existing conditions, operations, reclamation, and postmining use. Baseline data shall include, as applicable:

a.A description of the climatological factors representative of the permit area, including precipitation, prevailing winds, and temperature.

b.A description of the thickness and nature of the topsoil and subsoil within the proposed permit area. A soil survey and soil analyses conducted in accordance with standard methods acceptable to the director will be required to show variations in topsoil and subsoil depth and suitability. If a published soil survey is not available, a new survey must be prepared by a soil classifier as defined by North Dakota Century Code section 43-36-01.

c.A map which delineates existing vegetation types and a description, including cover, density, and productivity of the plant communities within the proposed permit area.

Included in this description shall be the results of an inventory conducted for any sensitive, threatened, or endangered plant species within the permit area.

d.Wildlife information shall be obtained for the permit area and adjacent area. Where species may be impacted beyond these areas, the information shall include, to the extent practicable, the area of potential impact.

e.A description of the ore body in the proposed permit area, including geologic plans and cross sections depicting the nature and depth of overburden, mineralized zone or ore body, and aquifers and springs. A description of the potential for geochemical alteration of overburden, ore body, and other materials present within the permit area. Detailed analyses may be required if the substrata is suspected to contain substances that are likely to create acid drainage or might degrade surface water or ground water or hinder reclamation.

f.Surface and ground water information, including:

(1)A map indicating the location of surface waters and the location and size of watersheds in and adjacent to the proposed permit area. The map shall depict all watercourses, lakes, natural and artificial water bodies, springs, and riparian and wetland areas. Streams shall be classified as ephemeral, intermittent, or perennial.

The map shall identify all watercourses, lakes, springs, and riparian and wetland areas into which surface or pit drainage will be discharged or may possibly be expected to reach;

(2)A description of surface drainage systems sufficient to identify the seasonal variation in surface water quantity and quality within the proposed permit and affected areas to the extent possible;

(3)Lithology and thickness of each geologic unit below the site indicating which units are water-bearing, cross sections and potentiometric maps indicating the locations of wells and the ground water flow direction in the vicinity of the site, and references or sources for this information;

(4)A description of the aquifer characteristics including total dissolved solids concentration, maximum and minimum depths to ground water, direction of flow and gradients, transmissivity and storativity, and a general description of ground water quality, and references or sources for this information; and (5)The location of all water wells and developed springs within and extending at least one mile from the proposed permit area. Water quality and quantity information for each well and spring shall be provided in the format required by the director.

g.A description and delineation on topographic maps of any prior mining operations which may have affected the permit area including, if known, the type of mining and processing method and a list of any processing chemicals or reagents used.

h.A list of accompanying map indicating all sites on or eligible for listing on the national register of historic places and known cemeteries and human burials within the proposed permit area. Included with this list and map shall be a description of the effects the proposed mining operations may have on these sites and any proposed mitigation measures.

i.A description of the present and historic land use of the permit area, the general patterns of land use in the surrounding areas, and a narrative of land capability and productivity based upon natural resource conservation service land use, capability classes, or a similar classification.

5.Operation plan. In addition to the information requested in subsection 3 of section 43-02-02.3-10, an applicant shall provide the following information as applicable;

a.The identification of any toxic-forming or acid-forming materials present or to be left on the site as a result of mining or mineral processing.

b.In addition to the estimated total acreages proposed to be disturbed, provide an estimate of acreage to be either disturbed or reclaimed annually during the permit term.

c.A description of the plan for saving, protecting, and replacing the topsoil and subsoil.

d.Maps and plans indicating the location, size, and capacities for the mine facilities, including:

(1)Leach pads, heaps, ore dumps, and stockpiles;

(2)Impoundments;

(3)Ponds;

(4)Diversions;

(5)Disposal systems;

(6)Pits;

(7)Tailings disposal facilities;

(8)Mills;

(9)Water treatment facilities;

(10)Storage areas for equipment, vehicles, fuel, chemicals, and solutions;

(11)Topsoil and subsoil stockpiles;

(12)Waste rock dumps; and (13)Other facilities or structures.

e.A contingency plan to mitigate impacts to wildlife when there has been an emergency or accidental discharge of toxic substances that may impact wildlife.

f.A description of measures which will be undertaken to control sedimentation from the permit area and a plan for the monitoring of nonpoint source sediment pollution from the disturbed area.

6.Impact assessment. The operator shall provide a general narrative description identifying potential surface and subsurface impacts. This description will include, at a minimum:

a.Projected impacts to surface and ground water systems;

b.Potential impacts to state and federal threatened and endangered species or their critical habitats;

c.Projected impacts of the mining operation on existing soil resources;

d.Projected impacts of mining operations on slope stability, erosion control, air quality, and public health and safety; and

e.Actions which are proposed to mitigate any of the above referenced impacts.

7.Reclamation plan. Each application shall include a reclamation plan, including maps or drawings as necessary, consisting of a narrative description of the proposed reclamation, including:

a.A statement of the current land use and the proposed postmining land use for the disturbed area, including a written preference statement from the surface owner for the proposed postmine land use.

b.A map at an appropriate scale and an approximate schedule indicating the reclamation activities to take place on disturbed areas of the mine site, including the number of acres to be reclaimed. The operator will be required to follow the sequence described unless modified or revised.

c.A description of the manner and the extent to which roads, highwalls, slopes, impoundments, drainages, pits and ponds, piles, drill holes, and similar structures will be reclaimed to the approximate original contour.

d.A detailed description of any surface facilities to be left as part of the postmining land use, included buildings, utilities, roads, pads, ponds, pits, and surface equipment where the postmine land use has been zoned as industrial or commercial land by the county.

e.A description of the treatment, location, and disposition of any toxic-forming or acid-forming materials generated and left onsite, including a map showing the location of such materials upon the completion of reclamation.

f.Plans for replacing the topsoil and subsoil that is removed and saved.

g.A planting program as best calculated to revegetate the disturbed area.

(1)Plans shall include, at a minimum, soil stabilization procedures, seedbed preparation, seed mixtures and rates, and timing of seeding.

(2)Where there is no original protective vegetative cover, an alternative practical procedure must be proposed to minimize or control erosion or siltation.

h.A topographic map of the anticipated surface configuration of the permit area upon completion of reclamation operations. The map shall be at appropriate contour intervals and scale.

i.A statement that the operator will conduct reclamation as required by these rules. 43-02-02.3-12. Review for completeness.

The department will determine whether the application is complete. The department will notify the applicant in writing, within thirty days after the application is submitted, whether the application is complete or specify deficiencies that must be corrected in order to complete the application. If the application is substantially deficient, it will be rejected. The department will notify the applicant when the application is considered complete. 43-02-02.3-13. Review period.

1.The department will have one hundred eighty days after the filing date to approve or disapprove the application.

2.The department may extend the review period not to exceed an additional one hundred eight days if:

a.Additional time is needed to correct application deficiencies.

b.Significant changes are submitted that in the department's judgment require additional time to review. The department may require additional public notification of the amended application.

c.The department requires additional time to conduct an informal conference or a formal hearing or complete the decision. 43-02-02.3-14. Permit application fees.

1.A fee of one hundred dollars must accompany the application for a small mining facility permit.

2.A fee of five hundred dollars plus ten dollars per acre must accompany the application for a large mining facility permit. 43-02-02.3-15. Information added after filing date.

Additional information submitted to the department by the applicant to supplement, correct, amend, or clarify an application following the filing date must also be submitted with the county recorder in the county or counties in which the proposed permit area is located. The additional information must be submitted at least thirty days before the hearing date. The applicant must transmit proof of submission with the county recorder to the department. The department shall give notice to the public of the additional information at least fifteen days before the scheduled hearing date. 43-02-02.3-16. Notice to agencies.

Within the first ten days of the review period of a permit application, the department shall send copies of the application to the department of agriculture, the state department of health, and the state water commission. 43-02-02.3-17. Notice of hearing.

Except in the case of an emergency, the commission will give thirty days' notice to the general public of the time and place of the hearing on the application by one publication in a newspaper of general circulation in the state capital and in a newspaper of general circulation in the county where the land affected, or some part, is situated. Immediately upon receiving notice of the hearing date, the permit applicant shall give notice by certified mail to surface and subsurface owners within the permit application area and to the county recorder in the county or counties in which the proposed permit area is located. 43-02-02.3-18. Permit approval or denial.

Within ninety days of the hearing, or a reasonable time thereafter, the department will notify the applicant of the commission's decision as to whether the permit is approved or denied. 43-02-02.3-19. Permit term.

1.The permit will remain in effect as long as active mining continues at a mine site and the operator remains in full compliance with all permit conditions.

2.A permit shall be reviewed and may be required to be modified or revised for any of the following:

a.Additional applicable requirements under North Dakota Century Code chapters 38-12 and 38-12.1 and North Dakota Administrative Code article 43-02; or

b.The director determines that the permit contains a material mistake or that inaccurate statements were made in establishing the terms or conditions of the permit.

3.If the permit area contains property owned by the federal or state government, the expiration or termination of the government's authorization for the operator to conduct mining operations on the property automatically suspends the operator's authority to continue mining operations on the property, although not necessarily reclamation operations, by the permit issued under

chapter 43-02-02.3. 43-02-02.3-20. Permit modifications or revision.

An application for a permit modification or revision shall be in a format acceptable to the director and shall be accompanied by sufficient information for the director to determine whether any of the factors listed in this section are present. A permit modification or revision will not be granted unless the director determines that the proposed modification or revision meets the requirements of this rule.

1.A permit modification or revision for a mining operation is required for:

a.Each new discrete processing, leaching, excavation, storage, or stockpile unit located within the permit area and not identified in the permit;

b.Each expansion of such a unit identified in the permit that exceeds the design limits specified in the permit; and

c.Any change in the approved reclamation plan.

2.The operator may request additional acreage [hectarage] if the department considers the addition an incidental boundary change to the original permit area.

3.The operator may file an application to withdraw any lands previously approved as a part of a permit area, except lands on which operations have commenced. The operator shall demonstrate and certify that the proposed acreage [hectarage] to be deleted has not been affected by mining activities. Applications to delete undisturbed acreage [hectarage] are not subject to the public notice, procedural, and approval or denial standards of North Dakota Century Code chapter 38-12.

4.Revisions are modifications that require public notice and an opportunity for public hearing pursuant to this rule. The director shall review each request for a permit modification to determine whether it must be processed as a revision.

a.The director shall consider the following factors and their level of impact to determine whether a permit modification would have a significant environmental impact requiring a revision:

(1)Whether the proposed change would authorize an expansion of design limits beyond that currently authorized by the permit that:

(a)Would be located in or is expected to have a direct surface impact on wetlands, springs, perennial or intermittent streams, lakes, rivers, or other water bodies or riparian areas.

(b)Is expected to have a direct impact on ground water that has a total dissolved solids concentration of less than ten thousand milligrams per liter.

(c)Is expected to result in point or nonpoint source surface or subsurface releases of acid or other toxic substances from the permit area.

(d)Would be located in designation critical habitat areas as determined in accordance with the federal Endangered Species Act of 1973 or in areas determined by the game and fish department likely to result in an adverse impact on an endangered species.

(e)Would adversely impact archaeological and historical areas.

(f)Would be located in a known cemetery or other burial ground.

(g)Would be located in an area designated as a federal wilderness area, a wilderness study area, an area of critical environmental concern, or an area within the national wild and scenic river system;

(2)Whether the proposed change would result in a significant increase in the required amount of financial assurance as determined by the director; or (3)Whether the proposed change would significantly depart from the nature or scale of the permit.

b.An application for a permit modification or revision shall be accompanied by sufficient information for the director to determine whether any of the factors listed in this section are present.

5.The following actions do not require permit modifications or revisions:

a.The construction, relocation, or modification of roads within the disturbed area that does not change the reclamation plan;

b.Placement or movement of support buildings, equipment areas, maintenance shops, monitoring facilities, wells, power lines, power poles, substations, and communications facilities within the disturbed area that does not change the reclamation plan; and

c.The movement of tanks, pipelines, utilities, and portable units. 43-02-02.3-21. Revocation and limitation of permits.

1.After notice and hearing, the commission may revoke a mining permit or limit its duration. The commission may act upon its own motion or upon the application of an owner in the permit area. In deciding whether to revoke or limit a permit, the factors that the commission may consider include:

a.The technical ability of the operator and other owners to conduct mining operations.

b.The experience of the operator and other owners in similar mining operations.

c.Contractual obligations, such as an expiring lease.

d.The amount of ownership the operator and other owners hold in the lease. If the operator is the majority owner or if its interest when combined with that of its supporters is a majority of the ownership, it is presumed that the operator should retain the permit. The presumption, even if not rebutted, does not prohibit the commission from limiting the duration of the permit. However, if the amount of the interest owned by the owner seeking revocation or limitation and its supporters are a majority of the ownership, the commission will presume that the permit should be revoked.

2.The commission may suspend a permit that is the subject of a revocation or limitation proceeding. A permit will not be suspended or revoked after operations have commenced.

3.If the commission revokes a permit upon the application of an owner and issues a permit to that owner or to another owner who supported revocation, the commission may limit the duration of such permit. The commission may also, if the parties fail to agree, order the owner acquiring the permit to pay reasonable costs incurred by the former operator and the conditions under which payment is to be made. The costs for which reimbursement may be ordered may include those involving survey of the well site, title search of surface and mineral title, and preparation of an opinion of mineral ownership.

4.If the commission declines to revoke a permit or limit the time within which it must be exercised, it may include a term in its order restricting the ability of the operator to renew the permit or to acquire another permit within the same spacing or drilling unit. 43-02-02.3-22. Operational practices.

The operator shall conform to the following practices:

1.The mining and reclamation operation shall be designed and operated using the most appropriate technology and best management practices.

2.Public safety and welfare. The operator shall minimize hazards to the public safety and welfare during operations. Methods to minimize hazards shall include:

a.The proper disposal of trash, scrap metal and wood, and extraneous debris;

b.The plugging or capping of drill, core, or other exploratory holes pursuant to section 43-02-02-24;

c.The posting of appropriate warning signs in locations where public access to operations is readily available; and

d.The construction of berms, fences, or barriers above highwalls or other excavations.

3.Drainages. If natural channels are to be affected by the mining operation, then the operator shall take appropriate measures to avoid or minimize environmental damage.

4.Erosion control. Operations shall be conducted in a manner such that sediment from disturbed areas is adequately controlled. The degree of erosion control shall be appropriate for the site-specific and regional conditions of topography, soil, drainage, water quality, or other characteristics.

5.Toxic-forming materials. All toxic-forming or potentially deleterious material shall be safely removed from the site or kept in an isolated condition such that adverse environmental effects are eliminated or controlled.

6.Soils. All available topsoil and subsoil shall be removed, stored, and stabilized. The salvaged topsoil and subsoil must be respread following the backfill and grading of disturbed areas.

7.Concurrent reclamation. During operations, disturbed areas shall be reclaimed as soon as practicable when no longer needed, except to the extent necessary to preserve evidence of mineralization or proof of discovery. Areas which have been disturbed but are not routinely or currently utilized shall be kept in a safe, environmentally stable condition. All reclamation work through seeding must be completed within three years of completion of mining. 43-02-02.3-23. Performance and reclamation standards and requirements.

The land surface of the permit area will be restored as nearly as possible to its original condition unless conflicting with the approved postmining land use. Each reclamation plan must be developed to meet the site-specific characteristics of the mining operation and the site.

1.Most appropriate technology and best management practices. The mining operation and the reclamation plan shall be designed and operated using the most appropriate technology and the best management practices.

2.Contemporaneous reclamation. Contemporaneous reclamation is required to the maximum extent practicable and in a manner that is consistent with the approved reclamation plan. All reclamation work must be completed within three years of completion of mining.

3.Assure protection. The mining operation and completed reclamation shall meet the following requirements established to assure protection of human health and safety, the environment, wildlife, and domestic animals.

a.Signs, markers and safeguarding. Measures will be taken to safeguard the public to prevent falls from highwalls or pit edges. Depending on site-specific characteristics, the following measures shall be required:

(1)Posting warning signs in locations near hazardous areas;

(2)Restricting access to hazardous areas;

(3)Marking the permit area boundaries;

(4)Posting a sign at the main entrances giving a telephone number of a person to call in the event of emergencies related to the mine; or (5)Other measures as needed to protect human safety.

b.Wildlife protection. Measures shall be taken to minimize adverse impacts on wildlife and important habitat. Based on site-specific characteristics, the following measures will be required:

(1)Restricting access of wildlife and domestic animals to toxic chemicals or otherwise harmful materials;

(2)Minimizing harm to wildlife habitat during mining; and (3)Reclaiming areas of wildlife habitat if not in conflict with the approved postmining land use.

c.Cultural resources. Cultural resources listed on or eligible for listing on the national register of historic places, and any cemeteries or burial grounds shall be protected until clearance has been granted by the appropriate authority.

d.Hydrologic balance. Operations shall be planned and conducted to minimize change to the hydrologic balance in both the permit and potentially affected areas. If not in conflict with the approved postmining land use, reclamation shall result in a hydrologic balance similar to premining conditions unless nonmining impacts have substantially changed the hydrologic balance.

(1)Operations shall be designed so that nonpoint source surface releases of acid or other toxic substances shall be contained within the permit area, and that all other surface flows from the disturbed area are treated to meet all applicable state and federal regulations.

(2)The disturbed areas shall not contribute suspended solids above background levels, or where applicable the state department of health standards, to ephemeral, intermittent, and perennial streams.

(3)To provide data to determine background levels for surface water entering the permit area, appropriate monitoring shall be conducted on drainages leading into the permit area.

(4)All diversions of overland flow shall be designed, constructed, and maintained to minimize adverse impacts to the hydrologic balance and to assure the safety of the public.

(a)No diversion shall be located so as to increase the potential for landslides.

(b)Unless site-specific characteristics require a different standard which is included in the approved permit, diversions which have watersheds larger than ten acres shall be designed, constructed, and maintained to safely pass the peak runoff from a ten-year, twenty-four-hour precipitation event.

(c)All diversion designs which have watersheds larger than ten acres shall be included in the permit application and certified by a registered professional engineer. Diversion designs shall be kept onsite or otherwise be made available, upon request, to the director for inspection.

(d)When no longer needed, temporary diversions shall be removed and the disturbed area reclaimed.

e.Stream diversions. When streams are to be diverted, the stream channel diversion shall be designed, constructed, and removed in accordance with the following:

(1)Unless site-specific characteristics require different measures to meet the performance standard and are included in the approved permit, the combination of channel, bank and floodplain configurations shall be adequate to safely pass the peak runoff of a ten-year, twenty-hour-hour precipitation event for temporary diversions, and a hundred-year, twenty-four-hour precipitation event for permanent diversions;

(2)The design and construction of all intermittent and perennial stream channel diversions shall be certified by a registered professional engineer. As-built drawings shall be completed promptly after construction and be included in the permit application and retained onsite or otherwise made available upon request to the director; and (3)When no longer needed, temporary stream channel diversions shall be removed and the disturbed area reclaimed.

f.Impoundments. If impoundments are required, they shall be designed, constructed, and maintained to minimize adverse impacts to the hydrologic balance and adjoining property and to assure the safety of the public.

(1)Unless site-specific characteristics require different measures to meet the performance standard and are included in the approved permit, impoundments having earthen embankments but not subject to the jurisdiction of the mine safety and health administration or the state department of health shall:

(a)Have a minimum elevation at the top of the settled embankment of two feet above the water surface in the pond with the spillway flowing at the design depth;

(b)Have a top width of the embankment not less than six feet;

(c)Have combined upstream and downstream side slopes of the settled embankment not less than five horizontal: one vertical with neither slope steeper than two horizontal: one vertical. Slopes shall be vegetated or otherwise stabilized to control erosion;

(d)Have the embankment foundation cleared of all vegetative matter, all surfaces sloped to no steeper than one horizontal: one vertical and the entire foundation area scarified;

(e)Have fill material free of vegetative matter and frozen soil;

(f)Have sufficient capacity for sediment storage and have sediment removed when that capacity is reached; and (g)Have spillways provided to safely discharge the peak runoff of a twenty-five-year, twenty-four-hour precipitation event, or an event with a ninety percent change of not being exceeded for the design life of the structure; or (h)Have other site-specific design criteria for embankments as long as they result in a minimum static safety factor for 1.3 with water impounded to the design level;

(i)Be designed and certified by a registered professional engineer. As-built drawings shall be completed promptly after construction and be retained onsite or otherwise made available upon request to the director; and (j)If necessary for sediment control, be in place before any other disturbance to the watershed for the impoundment.

(2)When no longer required, impoundments shall be graded to achieve positive drainage unless:

(a)The surface estate owner has requested in writing that they be retained;

(b)They are consistent with the approved reclamation plan; and (c)They are appropriate for the postmining land use for the self-sustaining ecosystem.

g.Minimization of mass movement. All temporary stockpiles shall be constructed and maintained to minimize mass movement.

h.Riparian and wetland areas. Disturbance to riparian and wetland areas shall be minimized during mining. Adverse effects to riparian and wetland areas shall be mitigated during reclamation unless the mitigation conflicts with the approved postmining land use.

i.Roads. Roads shall be constructed and maintained to control erosion.

(1)Drainage control structures shall be used as necessary to control runoff and to minimize erosion, sedimentation, and flooding. Culverts or other drainage facilities shall be installed as road construction progresses and shall be capable of safely passing a ten-year, twenty-four-hour precipitation event unless site-specific characteristics indicate a different standard is appropriate and is included in the approved permit. Culverts and drainage pipes shall be constructed and maintained to avoid plugging, collapsing, or erosion.

(2)Roads to be constructed in or across intermittent or perennial streams require site-specific designs to be submitted with the permit application.

(3)Permanent roads must be approved by the surface owner and be consistent with the approved postmining land use.

j.Explosives. Blasting shall be conducted to prevent injury to persons or damage to property not owned by the operator. Fly rock shall be confined to the permit area. The director may require a detailed blasting plan, preblast surveys or specify blast design limits to control possible adverse effects to structures.

4.Reclamation of surface facilities. The permit area shall be stabilized, to the extent practicable, to minimize future impact to the environment and protect air and water resources. Unless otherwise approved by the department, the reclamation of surface facilities shall include the removal of all buildings, road, and structures, and the surface restored as nearly as possible to its original condition. Tailings impoundments and ponds must be reclaimed and filled in and respread with topsoil and subsoil. All grading, backfilling, and topographic reconstruction must control erosion and sedimentation, protect areas outside the affected land from slides or other damage, and minimize the need for long-term maintenance.

Measures must be taken to reduce, to the extent practicable, the formation of acid and other toxic drainage that may otherwise occur following closure to prevent releases that cause federal or state standards to be exceeded. Nonpoint source surface releases for acid or other toxic substances shall be contained within the permit area.

Pond and impoundment reclamation must meet the following requirements:

a.Pond sludge must be chemically characterized to determine whether further treatment is necessary before disposal. Sludge must be removed for disposal at on offsite permitted solid waste facility or buried and covered onsite in a solid waste facility permitted in accordance with the applicable solid waste rules in North Dakota Administrative Code

article 33-20; and

b.Geomembranes must be removed from impoundments, unless it is demonstrated to the department's satisfaction that they will serve a useful function consistent with the approved postmining land use. The geomembrane material must be disposed of in a permitted landfill or may be disposed of onsite only if the operator first secures a solid waste permit in compliance with article 30-20.

5.Topsoil and subsoil. The operator shall take measures to remove and save all available topsoil and subsoil and protect it from erosion or contamination and assure that it is in a usable condition for sustaining vegetation when needed The following requirements shall be met unless site-specific characteristics mandate different requirements and those requirements are included in the approved permit.

a.Topsoil and subsoil shall be sampled and analyzed for vegetation establishment suitability:

(1)Sample spacing and interval shall be based on site-specific materials; and (2)Suitability will be identified by analysis based on site-specific materials.

b.Revegetation must be a component of the reclamation plan and all available topsoil and subsoil must be salvaged and replaced on disturbed areas.

c.Where direct distribution of topsoil and subsoil is not possible, it shall be stockpiled separately and in a manner to prevent loss of the resource.

d.Topsoil and subsoil shall be distributed in a manner to establish and maintain vegetation, consistent with the approved permit.

e.After distribution, topsoiled and subsoiled areas shall be stabilized to protect loss of the resource.

f.Where topsoil has been stockpiled for more than one year, the operator may be required to conduct analyses to determine if amendments are necessary.

6.Erosion control. Reclamation of disturbed lands must result in a condition that minimizes erosion. Revegetated lands must not contribute suspended solids above background levels, or where applicable, the state department of health standards, to streamflow of intermittent and perennial streams. Acceptable practices to control erosion include the following:

a.Stabilizing disturbed areas through land shaping, berming, or grading to final contour;

b.Minimizing reconstructed slope lengths and gradients;

c.Diverting runoff;

d.Establishing vegetation;

e.Regulating channel velocity of water;

f.Lining drainage channels with rock, vegetation, or other geotechnical materials; and

g.Mulching.

7.Revegetation. Revegetated lands must meet the following standards:

a.Revegetation success for a return as near as possible to original condition shall be determined through comparison of ground cover, productivity, and diversity and shall be made on the basis of the following approved reference areas:

(1)Foliage or basal cover and productivity of living perennial plants of the revegetated area shall be established equal to ninety percent of the reference area or equal to the approved revegetation standard using scientifically valid sampling techniques;

(2)Diversity of plant life forms (woody plants, grasses, forbs) shall consider what is reasonable based on the physical environment of the reclaimed area; and (3)Woody plant species shall be established to the approved density standard.

b.For areas for which the approved postmining land use is for wildlife habitat or forest land, success of vegetation shall be determined on the basis of tree or shrub stocking (density) and ground cover.

(1)The ground cover of living perennial plants shall be equal to ninety percent of the native ground cover of the reference area or other approved standard and shall be adequate to minimize erosion.

(2)Tree density for forest land shall have establishment rates of plant species equal to ninety percent of the approved reference area or other approved standard and shall be adequate to minimize erosion.

(3)If wildlife habitat is to be the postmining land use, the operator shall select and use plant species on the reclaimed areas based on the following criteria:

(a)Their proven nutritional value for fish and wildlife;

(b)Their uses as cover and security for wildlife;

(c)Their ability to support and enhance fish and wildlife habitat; and (d)Distribution of plant life forms to maximize benefits of edge effect, cover, and other benefits for fish and wildlife.

c.Revegetation for other postmining land shall be consistent with the approved postmining land use. Site-specific standards may include standards for foliar or basal cover, production, and diversity and will be included in the approved permit. 43-02-02.3-24. Report of production.

The operator of a mine shall, on or before the tenth day of the second month succeeding the month in which production occurs, file with the director the amount of production made by the mine upon form 5-sm or approved computer sheets no larger than eight and one-half by eleven inches [21.59 by 27.94 centimeters]. The report shall be signed by both the person responsible for the report and the person witnessing the signature. The printed name and title of both the person signing the report and the person witnessing the signature shall be included.

Production data submitted to the director shall be kept confidential for a period of one year when so requested by the operator. Such period may be further extended upon approval by the commission. 43-02-02.3-25. Annual report.

Every operator shall, on or before April thirtieth of each year after a permit has been issued, submit, on a form provided by the director, a report for the preceding calendar year. The report must:

1.Provide the status of the operation;

2.Provide production figures for the operation;

3.Identify, on a separate map, the location of the disturbed areas and, if reclaimed, the year in which the work was done;

4.Identify the number of acres disturbed, the number of acres reclaimed during the reporting year, and the number of acres which have not yet been reclaimed;

5.Indicate the current market value of any collateral posted as financial assurance in accordance with section 43-02-02.3-05; and

6.Indicate the compliance status for all existing state and federal environmental permits held by the operator for this operation. 43-02-02.3-26. Additional information may be required.

This chapter shall not be taken or construed to limit or restrict the authority of the commission to require the furnishing of such additional reports, data, or other information relative to production or products as may appear to be necessary or desirable, either generally or specifically, for the prevention of waste, protection of correlative rights, and the conservation of natural resources.

Chapter 43-02-02.4 Solution Mining

N.D. Admin. Code 43-02-02.4 Solution Mining

CHAPTER 43-02-02.4

SOLUTION MINING

Section 43-02-02.4-01Definitions 43-02-02.4-02Scope of Chapter 43-02-02.4-03Bond 43-02-02.4-04Designation and Responsibilities of Operator 43-02-02.4-05Permit Required 43-02-02.4-06Submission of Permit Application 43-02-02.4-07Summary Document 43-02-02.4-08Solution Mining Operation Permit Requirements 43-02-02.4-09Review for Completeness 43-02-02.4-10Review Period 43-02-02.4-11Permit Applications - Fees 43-02-02.4-12Information Added After Filing Date 43-02-02.4-13Notice to Agencies 43-02-02.4-14Notice of Hearing 43-02-02.4-15Permit Approval or Denial 43-02-02.4-16Permit Term 43-02-02.4-17Permit Modifications or Revision 43-02-02.4-18Revocation and Limitation of Permits 43-02-02.4-19Surface Facilities - Location - Exception to Location Requirements 43-02-02.4-20Operators of Class III Injection Wells 43-02-02.4-21Notice of Mechanical Integrity Testing 43-02-02.4-22Mechanical Integrity Testing 43-02-02.4-23Calibration of Pressure Gauges 43-02-02.4-24Reports of Mechanical Integrity Testing 43-02-02.4-25Mechanical Integrity Testing Required by the Director 43-02-02.4-26Cavity Size 43-02-02.4-27Subsidence Monitoring Above a Cavity Created by Solution Mining 43-02-02.4-28Abandonment of Cavity Created by Solution Mining 43-02-02.4-29Central Production Facility - Commingling of Production 43-02-02.4-30Production Equipment, Dikes, and Seals 43-02-02.4-31Tank Cleaning Permit 43-02-02.4-32Saltwater Handling Facilities 43-02-02.4-33Secondary Containment - General Requirements 43-02-02.4-34Secondary Containment - Vessels 43-02-02.4-35Secondary Containment - Loading and Unloading Areas 43-02-02.4-36Secondary Containment - Piping 43-02-02.4-37Secondary Containment - Certification 43-02-02.4-38Line Markers for Brine Pipelines 43-02-02.4-39Pipelines - Records 43-02-02.4-40Purging, Removal, and Abandonment of Lines and Vessels 43-02-02.4-41Existing Facilities - Maintenance 43-02-02.4-42Operational Practices 43-02-02.4-43Performance and Reclamation Standards and Requirements 43-02-02.4-44Report of Water Injected 43-02-02.4-45Report of Production 43-02-02.4-46Reports of Natural Brine Produced 43-02-02.4-47Solution Mining - Reporting 43-02-02.4-48Rock Profile Determination 43-02-02.4-49Books and Records to Be Kept to Substantiate Reports 43-02-02.4-50Additional Information May Be Required 43-02-02.4-01. Definitions.

The terms used throughout this chapter have the same meaning as in North Dakota Century Code

chapter 38-12, except:

1."Adjacent area" means land located outside the permit area where air, surface or ground water, fish, wildlife, vegetation, or other resources may be adversely impacted by solution mining and reclamation operations.

2."Certified or registered mail" means any form of service by the United States postal service, federal express, Pitney Bowes, and any other commercial, nationwide delivery service that provides the mailer with a document showing the date of delivery or refusal to accept delivery.

3."Department" means the department of mineral resources of the industrial commission.

4."Deposit" means an underground concentration containing a common accumulation of subsurface minerals.

5."Director" means the director of the department of mineral resources of the industrial commission.

6."Diversion" means a channel, embankment, or other manmade structure constructed to divert water from one area to another.

7."Field" means the general area underlaid by a concentration of subsurface minerals. Field also includes the geological formation containing such subsurface minerals.

8."Log or well log" means a systematic, detailed, and correct record of formations encountered in the drilling of a well, and includes commercial electrical logs and similar records.

9."Occupied dwelling" means a residence which is lived in by a person at least six months throughout a calendar year.

10."Product" means any commodity made from any subsurface mineral.

11."Saltwater handling facility" means any container, such as a pit, tank, or pool, whether covered or uncovered, used for the handling, storage, disposal of deleterious substances obtained, or used in connection with the drilling or operation of wells.

12."Solution mining" means the process of injecting fluid into a well to dissolve rock salt or other readily soluble rock or mineral, and the production of the resulting artificial brine.

13."Toxic-forming materials" means earth materials or wastes which, if acted upon by air, water, weathering, or microbiological processes, are likely to produce chemical or physical conditions in soils or water that are detrimental to biota or uses of water.

14."Waste" means:

a.Physical waste;

b.Operations which cause or tend to cause unnecessary or excessive surface loss; or

c.Operations that do not recover all of the mineral being mined that is technically and economically possible. 43-02-02.4-02. Scope of chapter.

This chapter contains general rules of statewide application which have been adopted by the industrial commission to conserve the natural resources of North Dakota, to prevent waste, and to provide for operation in a manner as to protect correlative rights of all owners of subsurface minerals.

Special rules, pool rules, field rules, and regulations and orders have been and will be issued when required and shall prevail as against general rules, regulations, and orders if in conflict therewith.

However, wherever this chapter does not conflict with special rules heretofore or hereafter adopted, this

chapter will apply in each case. The commission may grant exceptions to this chapter, after due notice and hearing, when such exceptions will result in the prevention of waste and operation in a manner to protect correlative rights. 43-02-02.4-03. Bond.

Before any person receives a permit to produce subsurface minerals via solution mining or commences extraction facility operations, the person shall submit to the commission, and obtain its approval, of a surety bond or cash bond. An alternate form of security may be approved by the commission after notice and hearing, as provided by law. The operator of a well or facility shall be the principal on the bond covering such activity. Each such surety bond shall be executed by a responsible surety company authorized to transact business in North Dakota.

1.Bond amounts and limitations for deep solution and injection wells.

a.For deep solution wells the amount of the bond shall be commensurate with the number of wells, the type of project, and the environmental risk. The amount of a bond will be determined by a formula that assigns reclamation costs based upon the number of drill sites, the depths of the holes, and the anticipated surface restoration costs.

b.Wells utilized for commercial disposal operations must be bonded in the amount of fifty thousand dollars.

When the principal on the bond is drilling or operating a number of wells within the state or proposes to do so, the principal may submit a bond conditioned as provided by law. A well with an approved temporary abandoned status shall have the same status as an exploratory, mineral, or injection well.

2.Extraction facility bond requirements. The amount of the bond shall be specified by the commission in the order approving the permit area and based upon facility size and estimated reclamation costs. Each surety bond shall be executed by a responsible surety company authorized to transact business in North Dakota.

3.Bond terms. Bonds shall be conditioned upon full compliance with North Dakota Century Code

chapter 38-12, and all administrative rules and orders of the commission, and continues until any of the following occurs:

a.The testholes or wells have been satisfactorily plugged which shall include practical reclamation of the well site and appurtenances thereto, and all logs, plugging records, and other pertinent data required by statute or rules and orders of the commission are filed and approved.

b.The mined lands or lands disturbed by any method of exploration or production of subsurface minerals have been restored and approved by the director.

c.The liability on the bond has been transferred to another bond and such transfer approved by the commission.

4.Transfer of property under bond. Transfer of property does not release the bond. In case of transfer of property or other interest in a well, extraction facility, or surface mining facility and the principal desires to be released from the bond covering the well or facility, such as producers, not ready for plugging, the principal must proceed as follows:

a.The principal must notify the director in writing of all proposed transfers of property at least thirty days before the closing date of the transfer. The director may, for good cause, waive this requirement.

The principal shall submit to the commission a form 8-sm reciting that a certain property, or properties, describing each by quarter-quarter, section, township, and range, is to be transferred to a certain transferee, naming such transferee, for the purpose of ownership or operation. The date of assignment or transfer must be stated and the form signed by a party duly authorized to sign on behalf of the principal.

On said transfer form the transferee shall recite the following: "The transferee has read the foregoing statement and accepts such transfer and the responsibility of such property under the transferee's one-well bond, surface mining facility bond, or extraction facility bond". Such acceptance must be signed by a party authorized to sign on behalf of the transferee and the transferee's surety.

b.When the commission has approved the transfer and acceptance and accepted it under the transferee's bond, the transferor shall be released from the responsibility of well plugging and site reclamation. If such wells include all the wells within the responsibility of the transferor's bond, such bond will be released by the commission upon written request. Such request must be signed by an officer of the transferor or a person authorized to sign for the transferor. The director may refuse to transfer any well from a bond if the well is in violation of a statute, rule, or order.

c.The transferee (new operator) of any extraction facility, surface mining facility, or injection well shall be responsible for the plugging and site reclamation of any such property. For that purpose, the transferee shall submit a new bond or, in the case of a surety bond, produce the written consent of the surety of the original or prior bond that the latter's responsibility shall continue and attach to such well. The original or prior bond shall not be released as to the plugging and reclamation responsibility of any such transferor until the transferee submits to the commission an acceptable bond to cover such well. All liability on bonds shall continue until the plugging and site reclamation of such property is completed and approved.

5.Bond termination. The commission shall, in writing, advise the principal and any sureties on any bond as to whether the plugging and reclamation is approved. If approved, liability under such bond may be formally terminated upon receipt of a written request by the principal. The request must be signed by an officer of the principal or a person authorized to sign for the principal.

6.Director's authority. The director is vested with the power to act for the commission as to all matters within this section, except requests for alternative forms of security, which may only be approved by the commission.

7.The director shall periodically review the amount of bond. The director may require adjustments to the amount of bond to reflect inflationary increases or increases in the anticipated costs of reclamation.

The commission may refuse to accept a bond if the operator or surety company has failed in the past to comply with statutes, rules, or orders relating to the operation of wells; if a civil or administrative action brought by the commission is pending against the operator or surety company; or for other good cause. 43-02-02.4-04. Designation and responsibilities of operator.

The principal on the bond covering a solution mining facility is the operator of the mine. The operator is responsible for compliance with all laws relating to the mine site. A dispute over designation of the operator of a well or mine site may be addressed by the commission. In doing so, the factors the commission may consider include those set forth in subsection 1 of section 43-02-02.4-18. 43-02-02.4-05. Permit required.

A permit is required prior to the commencement of drilling or mining. 43-02-02.4-06. Submission of permit applications.

Any person who conducts or expects to conduct solution mining operations shall file with the department a complete mining facility permit application, well permit application under chapter 43-02-02, an underground injection permit under chapter 43-02-2.1, and all required materials. The applicant shall file with the department proof that it submitted a copy of the applications to the county recorder in the county in which the proposed permit area is located. 43-02-02.4-07. Summary document.

The permit application must contain a summary document that describes the main elements of the operation and identifies the major environmental issues involved. 43-02-02.4-08. Solution mining operation permit requirements.

Permit applications for solution mining operations shall address the following:

1.Identification of interests to include:

a.The name and address of the operator responsible for the mining operations and reclamation of the site.

b.A listing of all parties, including addresses, which have an ownership and controlling interest in the operation. Alternatively, the applicant may submit the applicant's most recent 10k form required by the United States securities and exchange commission.

c.A statement of all current or previous mining operations within the United States held during the five years prior to application owned, operated, or controlled by any person identified in subdivision b and the names and addresses of regulatory agencies with jurisdiction over the environmental aspects of those operations and that could provide a compliance history for the operations.

d.The name and address of the surface landowners and mineral owners of all land to be affected by the mining operation.

e.The name and address of a designated agent for the service of notices and orders from the director.

f.The mine name and the mine safety and health administration identification number.

g.A listing of all federal and state permits required for the operation.

h.The identification of all property interests the applicant holds, including options, in the lands for which a permit is sought and in all contiguous land. This identification must cover surface and subsurface interests and legal descriptions must be provided identifying the location of each interest and option.

2.Project location description and maps plotted at a scale to accurately identify locational landmarks and operational details, to include:

a.A legal description of the proposed permit area.

b.The general location as shown on a topographic map which gives the location of the following: perennial, intermittent, and ephemeral streams; springs and seeps; wetlands, riparian areas, lakes and other water bodies; residences, businesses, and other structures; existing and proposed roads; other access routes; support facilities; cemeteries; burial grounds; cultural resources listed on the national register of historic places; electrical transmission and communication lines; pipelines; and oil, gas, and water wells on and within one-half mile of the permit area.

c.An operations map which identifies:

(1)The area to be disturbed;

(2)The location of any existing or proposed operations including access roads, drill holes, trenches, pits, cuts, or other planned small mining activities; and (3)Any adjacent previous disturbance for which the operator is not responsible.

d.A surface facilities map which identifies: buildings; stationary mining/processing equipment; roads; utilities; power lines; proposed drainage control structures; the location of topsoil and subsoil storage areas; tailings or processed waste facilities; disposal areas for overburden; solid and liquid wastes and wastewater discharge treatment and containment facilities.

3.Sampling and analysis plan.

a.The applicant shall submit a proposed sampling and analysis plan (SAP) to the director for review prior to baseline data collection. Four copies should be submitted to facilitate the review. The proposed SAP should contain, at a minimum, the following information for each relevant resource:

(1)Sampling objectives;

(2)A list of the data to be collected;

(3)Methods of collection;

(4)General water chemistry and the parameters to be analyzed for;

(5)Maps indicating the proposed sampling locations;

(6)Sampling frequency; and (7)Laboratory and field quality assurance plans.

b.The director shall distribute the proposed SAP to other agencies as determined by the director. The agencies will have thirty days from receipt of the proposed SAP to submit written comments to the director. Any written comments received within thirty days shall be provided to the applicant. The director shall also provide written comments and recommendations to the applicant on the adequacy of the SAP.

c.The applicant may request a conference with the director to discuss the SAP.

4.Baseline data. Descriptions, maps, drawing, or photographs shall be included as required for determination of existing conditions, operations, reclamation, and postmining use. Baseline data shall include, as applicable:

a.A description of the climatological factors representative of the permit area including precipitation, prevailing winds, and temperature.

b.A description of the thickness and nature of the topsoil and subsoil within the proposed permit area. A soil survey and soil analyses conducted in accordance with standard methods acceptable to the director will be required to show variations in topsoil and subsoil depth and suitability. If a published soil survey is not available, a new survey must be prepared by a soil classifier as defined by North Dakota Century Code section 43-36-01.

c.A map which delineates existing vegetation types and a description, including cover, density, and productivity of the plant communities within the proposed permit area.

Included in this description shall be the results of an inventory conducted for any sensitive, threatened, or endangered plant species within the permit area.

d.Wildlife information shall be obtained for the permit area and adjacent area. Where species may be impacted beyond these areas, the information shall include, to the extent practicable, the area of potential impact.

e.A description of the ore body in the proposed permit area, including geologic plans and cross sections depicting the nature and depth of overburden, mineralized zone or ore body, and aquifers and springs. A description of the potential for geochemical alteration of overburden, ore body, and other materials present within the permit area. Detailed analyses may be required if the substrata is suspected to contain substances that are likely to create acid drainage or might degrade surface water or ground water or hinder reclamation.

f.Surface and ground water information to include:

(1)A map indicating the location of surface waters and the location and size of watersheds in and adjacent to the proposed permit area. The map shall depict all watercourses, lakes, natural or artificial water bodies, springs, and riparian and wetland areas. Streams shall be classified as ephemeral, intermittent, or perennial.

The map shall identify all watercourses, lakes, springs, and riparian and wetland areas into which surface or pit drainage will be discharged or may possibly be expected to reach;

(2)A description of surface drainage systems sufficient to identify the seasonal variation in surface water quantity and quality within the proposed permit and affected areas to the extent possible;

(3)Lithology and thickness of each geologic unit below the site indicating which units are water bearing, cross sections and potentiometric maps indicating the locations of wells and the ground water flow direction in the vicinity of the site, and references or sources for this information;

(4)A description of the aquifer characteristics, including total dissolved solids concentration, maximum and minimum depths to ground water, direction of flow and gradients, transmissivity and storativity, and a general description of ground water quality, and references or sources for this information; and (5)The location of all water wells and developed springs within and extending at least one mile form the proposed permit area. Water quality and quantity information for each well and spring shall be provided in the format required by the director.

g.A description and delineation on topographic maps of any prior mining operations which may have affected the permit area including, if known, the type of mining and processing method and a list of any processing chemicals or reagents used.

h.A list and accompanying map indicating all sites on or eligible for listing on the national register of historic places and known cemeteries and human burials within the proposed permit area. Included with this list and map shall be a description of the effects of the proposed mining operations may have on these sites and any proposed mitigation measures.

i.A description of the present and historic land use of the permit area, the general patterns of land use in the surrounding areas, and a narrative of land capability and productivity based upon natural resource conservation service land use.

5.Operation plan. Provide a brief narrative description of the proposed mining operation. The description must include the following information:

a.A general description of the minerals sought, the methods of extraction, and any processing to be conducted onsite. Any chemicals to be used on site must be identified.

b.An estimate of depth to ground water and total dissolved solids concentration.

c.Estimated width and length of any new roads to be constructed.

d.The identification of any toxic-forming or acid-forming materials present or to be left on the site as a result of mining or mineral processing.

e.A discussion of plans for saving and replacing topsoil and subsoil from the areas to be affected.

f.The amount of material (including mineral deposit, overburden, waste rock, or core hole material) to be extracted, moved, or proposed to be moved, relating to the mining operation.

g.Maps and plans indicating the location, size, and capacities for the mine facilities, including:

(1)Leach pads, heaps, ore dumps, and stockpiles;

(2)Impoundments;

(3)Ponds;

(4)Diversions;

(5)Disposal systems;

(6)Pits;

(7)Tailings disposal facilities;

(8)Mills;

(9)Water treatment facilities;

(10)Storage areas for equipment, vehicles, fuel, chemicals, and solutions;

(11)Topsoil and subsoil stockpiles;

(12)Waste rock dumps; and (13)Other facilities or structures.

h.Plans for any structures that will be used for managing runoff from the disturbed areas and a discussion of other sediment control measures that will be used.

i.A contingency plan to mitigate impacts to wildlife when there has been an emergency or accidental discharge of toxic substances that may impact wildlife.

6.Reclamation plan. A reclamation plan will include maps or drawings as necessary and a narrative description of the proposed reclamation, including:

a.A statement of the current land use and the proposed postmining land use for the disturbed area, including a written preference statement from the surface owner for the proposed postmine land use.

b.A description of the manner and the extent to which roads, highwalls, slopes, impoundments, drainages, pits and ponds, piles, drill holes, and similar structures will be reclaimed to the approximate original contour.

c.A detailed description of any surface facilities to be left as part of the postmining land use, including buildings, utilities, roads, pads, ponds, pits, and surface equipment in those instances where the postmine land use has been zoned as industrial or commercial land by the county.

d.A description of the treatment, location, and disposition of any toxic-forming or acid-forming materials generated and left onsite, including a map showing the location of such materials upon the completion of reclamation.

e.Plans for replacing the topsoil and subsoil that is removed and saved.

f.A planting program as best calculated to revegetate the disturbed area.

(1)Plans shall include, at a minimum, soil stabilization procedures, seedbed preparation, seed mixtures and rates, and timing of seeding.

(2)Where there is no original protective vegetative cover, an alternative practical procedure must be proposed to minimize or control erosion or siltation.

g.A topographic map of the anticipated surface configuration of the permit area upon completion of reclamation operations. The map shall be at appropriate contour intervals and scale.

h.A statement that the operator will conduct reclamation as required by these rules. 43-02-02.4-09. Review for completeness.

The department will determine whether the application is complete. The department will notify the applicant in writing, within thirty days after the application is submitted, whether the application is complete or whether there are specific deficiencies that must be corrected in order to complete the application. If the application is substantially deficient, it will be rejected. The department will notify the applicant when the application is considered complete. 43-02-02.4-10. Review period.

1.The department will have one hundred eighty days after the filing date to approve or disapprove the application.

2.The department may extend the review period not to exceed an additional one hundred eight days if:

a.Additional time is needed to correct application deficiencies;

b.Significant changes are submitted that in the department's judgement require additional time to review. The department may require additional public notification of the amended application; or

c.The department requires additional time to conduct an informal conference or a formal hearing to complete the decision. 43-02-02.4-11. Permit applications - Fees.

A fee of five hundred dollars must accompany the permit application. 43-02-02.4-12. Information added after filing date.

Additional information submitted to the department by the applicant to supplement, correct, amend, or clarify an application following the filing date must also be submitted with the county recorder in the county or counties in which the proposed permit area is located. The additional information must be submitted at least thirty days before the hearing date. The applicant must provide proof of submission to the county recorder to the department. The department shall give notice to the public of the additional information at least fifteen days before the scheduled hearing date. 43-02-02.4-13. Notice to agencies.

Within the first ten days of the review period of a permit application, the department shall send copies of the application to the department of agriculture, the state department of health, and to the state water commission. 43-02-02.4-14. Notice of hearing.

Except in the case of an emergency, the commission will give thirty days' notice to the general public of the time and place of the hearing on the application. Immediately upon receiving notice of the hearing date, the permit applicant shall give notice by certified mail to surface and subsurface owners within the permit application area and to the county recorder in the county or counties in which the proposed permit area is located. 43-02-02.4-15. Permit approval or denial.

Within ninety days of the hearing, or a reasonable time thereafter, the department will notify the applicant of the commission's decision as to whether the permit is approved or denied. 43-02-02.4-16. Permit term.

1.The permit will remain in effect as long as active mining continues at a mine site and the operator remains in full compliance with all permit conditions.

2.A permit shall be reviewed and may be required to be modified or revised due to:

a.Additional applicable requirements under North Dakota Century Code chapters 38-12 and 38-12.1 and North Dakota Administrative Code article 43-02; or

b.The director determining that the permit contains a material mistake or that inaccurate statements were made in establishing the terms or conditions of the permit.

3.If the permit area contains property owned by the federal or state government, the expiration or termination of the government's authorization of the operator to conduct mining operations on the property automatically revokes the operator's permit, but does not suspend the operator's reclamation operations. 43-02-02.4-17. Permit modifications or revision.

An application for a permit modification or revision shall be in a format acceptable to the director and shall be accompanied by sufficient information for the director to determine whether any of the factors listed in the section are present. A permit modification or revision will not be granted unless the director determines that the proposed modification or revision meets the requirements of this section.

1.A permit modification or revision for a mining operation is required for:

a.Each new discrete processing, leaching, excavation, storage, or stockpile unit located within the permit area and not identified in the permit;

b.Each expansion of such a unit identified in the permit that exceeds the design limits specified in the permit; and

c.Any change in the approved reclamation plan.

2.Revisions are modifications that require public notice and an opportunity for public hearing pursuant to this rule. The director shall review each request for a permit modification to determine whether it must be processed as a revision.

a.The director shall consider the following factors and their level of impact to determine whether a permit modification would have a significant environmental impact requiring a revision:

(1)Whether the proposed change would authorize an expansion of design limits beyond that currently authorized by the permit that:

(a)Would be located in or is expected to have a direct surface impact on wetlands, springs, perennial or intermittent streams, lakes, rivers, and other water bodies or riparian areas.

(b)Is expected to have a direct impact on ground water that has a total dissolved solids concentration of less than ten thousand milligrams per liter.

(c)Is expected to result in point or nonpoint source surface or subsurface releases of acid or other toxic substances from the permit area.

(d)Would be located in designated critical habitat areas as determined in accordance with the federal Endangered Species Act of 1973 or in areas determined by the game and fish department likely to result in an adverse impact on an endangered species.

(e)Would adversely impact cultural resources listed on either the national register of historic places or the state register of cultural properties.

(f)Would be located in a known cemetery or other burial ground.

(g)Would be located in an area designated as a federal wilderness area, a wilderness study area, an area of critical environmental concern, or an area within the national wild and scenic river system.

(2)Whether the proposed change would result in a significant increase in the required amount of financial assurance as determined by the director; or (3)Whether the proposed change would significantly depart from the nature or scale of the permit.

b.An application for a permit modification or revision shall be accompanied by sufficient information for the director to determine whether any of the factors listed in this section are present.

3.The following actions do not require permit modifications or revisions:

a.The construction, relocation, or modification of roads within the disturbed area that does not change the reclamation plan;

b.Placement or movement of support buildings, equipment areas, maintenance shops, monitoring facilities, wells, power lines, power poles, substations, and communications facilities within the disturbed area that does not change the reclamation plan; and

c.The movement of tanks, pipelines, utilities, and portable units. 43-02-02.4-18. Revocation and limitation of permits.

1.After notice and hearing, the commission may revoke a mining permit or limit its duration. The commission may act upon its own motion or upon the application of an owner in the permit area. In deciding whether to revoke or limit a permit, the factors that the commission may consider include:

a.The technical ability of the operator and other owners to conduct mining operations.

b.The experience of the operator and other owners in similar mining operations.

c.Contractual obligations, such as an expiring lease.

d.The amount of ownership the operator and other owners hold in the lease. If the operator is the majority owner or if its interest when combined with that of its supporters is a majority of the ownership, it is presumed that the operator should retain the permit. This presumption, even if not rebutted, does not prohibit the commission from limiting the duration of the permit. However, if the amount of the interest owned by the owner seeking revocation or limitation and its supporters are a majority of the ownership, the commission will presume that the permit should be revoked.

2.The commission may suspend a permit that is the subject of a revocation or limitation proceeding. A permit will not be suspended or revoked after operations have commenced.

3.If the commission revokes a permit upon the application of an owner and issues a permit to that owner or to another owner who supported revocation, the commission may limit the duration of such permit. The commission may also, if the parties fail to agree, order the owner acquiring the permit to pay reasonable costs incurred by the former operator and the conditions under which payment is to be made. The costs for which reimbursement may be ordered may include those involving survey of the well site, title search of surface and mineral title, and preparation of an opinion of mineral ownership.

4.If the commission declines to revoke a permit or limit the time within which it must be exercised, it may include a term in its order restricting the ability of the operator to renew the permit or to acquire another permit within the same spacing or drilling unit. 43-02-02.4-19. Surface facilities - Location - Exception to location requirements.

1.All surface facilities and flow lines installed shall be constructed so that the materials contained in the facilities do not cause waste. Operation of surface facilities and flow lines shall not begin until the operator has complied with the methods and means to prevent pollution as specified in these rules.

2.Surface facilities may not be located less than five hundred feet from either of the following:

a.Existing recorded freshwater wells and reasonably identifiable freshwater wells utilized for human consumption.

b.Occupied dwellings.

3.Surface facilities may be located closer than five hundred feet from existing recorded freshwater wells and reasonably identifiable freshwater wells utilized for human consumption and occupied dwellings under either of the following conditions:

a.Upon presentation to the director of a written consent signed by the owner or owners of all existing recorded freshwater wells and reasonably identifiable freshwater wells utilized for human consumption and occupied dwellings.

b.After notice and hearing, the commission determines that the proposed surface facility location will prevent waste, protect environmental values, and not compromise public safety.

4.The director shall be notified within twenty-four hours of emergency repairs to existing surface facilities that substantially modify the facility or piping. Details regarding such emergency repairs, including changes in size or location of facility structures or piping, shall be submitted in writing within thirty days of the repair. 43-02-02.4-20. Operators of class III injection wells.

Prior to the construction of any injection well to be utilized for the extraction of minerals or energy, an operator shall obtain an underground injection control permit pursuant to chapter 43-02-02.1. 43-02-02.4-21. Notice of mechanical integrity testing.

At least thirty days before a regularly scheduled test, an operator shall notify the director of the date and approximate time of the test. The notification shall include a copy of the proposed test procedure, including procedures for wireline logging. Mechanical integrity testing shall not be conducted until an operator has received approval of the test procedure from the director. Mechanical integrity testing may be witnessed by the director. 43-02-02.4-22. Mechanical integrity testing.

1.Prior to commencing operations, the operator of a new injection well must demonstrate the mechanical integrity of the well. Injection wells must demonstrate continual mechanical integrity and be tested at least once every five years. An injection well has mechanical integrity if:

a.There is no significant leak in the casing, tubing, or packer; and

b.There is no significant fluid movement into an underground source of drinking water or an unauthorized zone through vertical channels adjacent to the injection bore.

2.One of the following methods must be used to evaluate the absence of significant leaks:

a.Pressure test with liquid or gas.

b.Monitoring of positive annulus pressure following a valid pressure test.

c.Radioactive tracer survey.

3.One of the following methods must be used to establish the absence of significant fluid movement:

a.A log from which cement can be determined or well records demonstrating the presence of adequate cement to prevent such migration.

b.Radioactive tracer survey, temperature log, or noise log. 43-02-02.4-23. Calibration of pressure gauges.

The operator shall calibrate all pressure gauges used in mechanical integrity demonstrations according to the manufacturer's recommendations. A copy of the calibration certificate shall be submitted to the director at the time of demonstration and every time the gauge is calibrated. A pressure gauge shall have a resolution so as to allow detection of at least one-half of the maximum allowable pressure change. 43-02-02.4-24. Reports of mechanical integrity.

The operator shall file a signed copy of the report of a mechanical integrity test with the director within sixty days after testing. A copy of the pressure record shall accompany the report. The report shall include evaluation of the test results by a person qualified to provide such an evaluation. Reports of mechanical integrity demonstrations utilizing downhole logs shall be accompanied by an interpretation of the log by a person qualified to make such interpretations. 43-02-02.4-25. Mechanical integrity testing required by the director.

The director may require a demonstration of mechanical integrity following a change of well status or if there is reason to believe a well does not have mechanical integrity. 43-02-02.4-26. Cavity size.

The operator of a solution well shall submit a plan to monitor cavity size and shape for approval by the director. The plan shall include frequency of monitoring and shall include a description of the method used to determine the size and shape of the cavity. 43-02-02.4-27. Subsidence monitoring above a cavity created by solution mining.

The operator shall submit a plan for subsidence monitoring above a cavity for approval by the director. The plan shall include frequency of monitoring and shall include a description of the method used to monitor subsidence. 43-02-02.4-28. Abandonment of cavity created by solution mining.

Before abandoning a cavity used for storage, the operator shall remove stored product to the extent practicable and replace it with brine or freshwater subject to the approval of the director. 43-02-02.4-29. Central production facility - Commingling of production.

1.The director shall have the authority to approve requests to consolidate production equipment at a central location.

2.Commingling of production from two or more wells in a central production facility is prohibited unless approved by the director. There are two types of central production facilities that may be approved by the director.

a.A central production facility in which all production going into the facility has common ownership (working interests, royalty interests, and overriding royalties), known as a common ownership central production facility. The director may approve a common ownership central production facility provided the production from each well can be accurately determined at reasonable intervals.

b.A central production facility in which production going into the facility has diverse ownership, known as a diverse ownership central production facility. The director may approve a diverse ownership central production facility provided the production from each well is accurately metered prior to commingling. A diverse ownership central production facility that is not metered prior to commingling may only be approved by the commission after notice and hearing.

3.Common ownership central production facility. The application for permission to commingle solutions must be submitted on a sundry notice (form 4-sm) and shall include the following:

a.A plat or map showing thereon the location of the central facility and the name, well file number, and location of each well and flow lines from each well that will produce into the facility.

b.A schematic drawing of the facility which diagrams the testing, treating, routing, and transferring of production. All pertinent items should be shown, such as treaters, tanks, flow lines, valves, meters, and recycle pumps.

c.An affidavit executed by a person who has knowledge as to the state of title demonstrating common ownership.

d.An explanation of the procedures or method to be used to accurately determine individual well production at periodic intervals. Such procedures or method shall be performed at least once every three months.

A copy of all tests are to be filed with the director on form 11-sm within thirty days after the tests are completed.

4.Diverse ownership central production facility. The application for permission to commingle solutions must be submitted on a sundry notice (form 4-sm) and shall include the following:

a.A plat or map showing thereon the location of the central facility and the name, well file number, and location of each well, and flow lines from each well that will produce into the facility.

b.A schematic drawing of the facility which diagrams the testing, treating, routing, and transferring of production. All pertinent items should be shown, such as treaters, tanks, flow lines, valves, meters, and recycle pumps.

c.The name of the manufacturer, size, and type of meters to be used. The meters must be proved at least once every three months and the results reported to the director within thirty days following the completion of the test.

d.An explanation of the procedures or method to be used to accurately determine individual well production at periodic intervals. Such procedures or method shall be performed monthly.

A copy of all tests are to be filed with the director on form 11-sm within thirty days after the tests are completed.

5.Any changes to a previously approved central production facility must be reported on a sundry notice (form 4-sm) and approved by the director. 43-02-02.4-30. Production equipment, dikes, and seals.

Storage of brine solution in underground or partially buried tanks or containers is prohibited.

Surface tanks and production equipment must be devoid of leaks and in good condition. Unused tanks and production equipment must be removed from the site or placed into service, within a reasonable time period, not to exceed one year. Dikes must be erected and maintained around tanks at any production facility.

Dikes must be erected around tanks at any new production facility within thirty days after the well has been completed. Dikes as well as the base material under the dikes and within the diked area must be constructed of sufficiently impermeable material to provide emergency containment. Dikes must be of sufficient dimension to contain the total capacity of the largest tank plus one day's fluid production.

The required capacity of the dike may be lowered by the director if necessity can be demonstrated to the director's satisfaction.

Numbered metal security seals shall be properly utilized on all access valves and access points to secure the tank or battery of tanks. 43-02-02.4-31. Tank cleaning permit.

No tank bottom waste shall be removed from any tank used for the storage or sale of crude oil without prior approval by the director. Verbal approval may be given. Prior approval to remove tank bottom waste from tanks not used for the storage or sale of crude oil is not required.

Within thirty days of the removal of the tank bottom waste of any tank used for the storage or sale of crude oil, the owner or operator shall submit a report (form 10-sm) showing an accurate gauge of the contents of the tank and the amount of merchantable oil determinable from a representative sample of the tank bottom by the standard centrifugal test as prescribed by the American petroleum institute's code for measuring, sampling, and testing crude oil.

Within thirty days of the removal of the tank bottom waste of any permanent tank not used for the storage or sale of crude oil, the owner or operator shall submit a sundry notice (form 4-sm) detailing the cleaning operation.

All tank bottom waste must be disposed of in a manner authorized by the director and in accordance with all applicable local, state, and federal laws and regulations. Nothing contained in this

section shall apply to reclaiming of pipeline break oil or the treating of tank bottoms at a pipeline station, crude oil storage terminal, or refinery or to the treating by a gasoline plant operator of oil and other catchings collected in traps and drips in the gas-gathering lines connected to gasoline plants and in scrubbers at such plants. 43-02-02.4-32. Saltwater handling facilities.

1.All saltwater liquids or brines produced shall be processed, stored, and disposed of without pollution of freshwater supplies. At no time shall saltwater liquids or brines be allowed to flow over the surface of the land or into streams.

2.Underground injection of saltwater liquids and brines for the purpose of solution mining shall be in accordance with chapter 43-02-02.1.

3.Underground injection of a waste product shall be in accordance with chapter 33-25-01.

4.The operator shall take steps to minimize the amount of solids stored at the facility. 43-02-02.4-33. Secondary containment - General requirements.

Secondary containment measures at a wellhead or surface facility shall meet all of the following requirements:

1.The sidewalls and floor of a secondary containment area shall be constructed of sufficiently impermeable material to provide emergency containment.

2.Dikes or firewalls shall be maintained and the enclosure kept free of waste products, stored products, tank bottoms, brine, water, vegetation, debris, and any flammable or combustible material.

3.Dikes must be of sufficient dimension to contain the total capacity of the largest tank plus one day's fluid production.

4.An operator shall install an automatic surface facility shutdown system designed to prevent liquids from overflowing the secondary containment area. A surface facility shall be exempt from the requirement of an automatic shutdown system if the facility has staff present while operating and is equipped with alarm systems on the storage tank or tanks.

5.All transfer and injection pumps shall have leak containment constructed to prevent the seepage of any liquids moved by the pump or any lubricating oils into the surrounding soils, surface waters, or ground water.

6.Wellheads and flare stacks shall have secondary containment and spill containment areas constructed in a manner to prevent the seepage of waste product, stored product, or brine into the surrounding soils, surface waters, or ground water. Secondary containment at the wellhead shall be constructed in a manner to capture leakage of liquid that may occur. In addition, if the wellhead is equipped with a pump jack utilizing a gasoline or diesel-powered engine, then the engine shall also have secondary containment that is sufficient to prevent the seepage of any machine oils or fuels into the surrounding soils, surface waters, or ground water.

7.An operator shall keep secondary containment areas free of standing liquid. All spills in a secondary containment area shall be pumped up within forty-eight hours of discovering the spill.

8.An operator shall submit to the director a plan for inspections and monitoring of active wells and surface facilities. 43-02-02.4-34. Secondary containment - Vessels.

A vessel at a surface facility shall be elevated and placed on impervious pads or constructed so that any leakage can be easily detected. A vessel that is to be used onsite for thirty days or less shall, at a minimum, be placed on leak-resistant material installed in a manner to contain spills or leaks.

A waste product, stored product, or brine storage vessel shall be located in a secondary containment area. 43-02-02.4-35. Secondary containment - Loading and unloading areas.

1.A truck loading and unloading area located outside of a secondary containment area shall be constructed and sealed in a manner that prevents the seepage of waste product, stored product, or brine into the surrounding soils, surface waters, or ground water. In addition, a ramp shall be constructed to contain any leakage from transfer operations at the vehicle being loaded or unloaded. The ramp area shall contain a sump and be connected to a secondary containment area so that any spillage drains into the sump and into the secondary containment area. The spill containment ramp and sump shall have a combined capacity of not less than one thousand gallons.

2.Sumps shall be constructed of materials impervious to the waste product, stored product, and brine and resistant to damage and deterioration during use. Sumps shall be connected to the ramp area and the secondary containment area in a manner that prevents leakage.

3.All loading and unloading facility transfer lines that are not in use shall be secured to prevent spillage. A shutoff valve shall be installed at the truck connect point and at the storage vessels.

All shutoff valves shall be left in a normally closed position. 43-02-02.4-36. Secondary containment - Piping.

All piping at a surface facility shall be routed above the ground and kept within the secondary containment area where practicable. Piping that cannot be routed above the ground shall have its location marked with posts or with other location-identifying markers approved by the director so that the buried piping can be easily located. 43-02-02.4-37. Secondary containment - Certification.

Upon completion of the construction of a surface facility, but before its use, an operator of a well shall certify to the director that the secondary containment area is constructed according to the approved plan. Following advance notice, the director may require an inspection of a surface facility before it is put into service. If an inspection is required it shall be conducted within five business days of the receipt of certification. 43-02-02.4-38. Line markers for brine pipelines.

If a pipeline conveys liquids to or from a well located outside the perimeter of a manufacturing plant, it is subject to the provisions of this section.

1.Except as provided in subsection 2, a marker shall be placed and maintained as close as practicable over each buried brine pipeline, as follows:

a.At each crossing of a public road and railroad.

b.When necessary to identify the location of the brine pipeline to reduce the possibility of damage or interference.

c.At the point of crossing of or under waterways and other bodies of water.

2.Markers shall be placed and maintained along each section of a brine pipeline that is located aboveground in an area which is accessible to the public.

3.The following information shall be written legibly on a background of sharply contrasting color on each brine pipeline marker:

a.The word "warning", or "caution", followed by the words "waste product brine" or "brine pipeline", all of which, except for markers in heavily developed urban areas, shall be not less than one and one-half inches high and legible under normal conditions at a distance of twenty-five feet.

b.The name of the operator and the telephone number, including the area code, where the operator can be reached at all times. 43-02-02.4-39. Pipelines - Records.

An operator shall keep records covering each leak discovered, repair made, pipeline break, pipeline patrol, and inspection for as long as the segment of pipeline involved remains in service. 43-02-02.4-40. Purging, removal, and abandonment of lines and vessels.

An operator of a well shall remove all flow lines and vessels, including tanks, if the flow lines or vessels are not used for one year and shall provide notification of the removal to the director. The director may allow a line to be purged and abandoned in place upon written application from the operator. The director may grant an exception to this section upon written application. 43-02-02.4-41. Existing facilities - Maintenance.

1.The operator of a well shall maintain all existing dikes or firewalls installed before July 1, 2013, and shall keep the containment area free of oil, emulsions, waste products, stored products, tank bottoms, brine, water, vegetation, debris, or any flammable or combustible material.

2.The director may require surface facilities constructed before July 1, 2013, to be upgraded to meet secondary containment requirements of this chapter if the facility is substantially modified or if losses have resulted in pollution.

3.Before any modification of a secondary containment area, other than routine maintenance, the operator of a well shall notify the director in writing. The notification shall include a modified secondary containment plan reflecting the proposed changes. The operator shall receive approval from the director before making the modification. The director shall approve or deny the request within eleven days of receipt of the request. The director may require an inspection of the modified secondary containment area before it is returned to service. 43-02-02.4-42. Operational practices.

The operator shall conform to the following practices:

1.The mining and reclamation operation shall be designed and operated using the most appropriate technology and best management practices.

2.Public safety and welfare. The operator shall minimize hazards to the public safety and welfare during operations. Methods to minimize hazards shall include:

a.The disposal of trash, scrap metal and wood, and extraneous debris;

b.The plugging or capping of drill, core, or other exploratory holes pursuant to section 43-02-02-24;

c.The posting of appropriate warning signs in locations where public access to operations is readily available; and

d.The construction of berms, fences, or barriers above highwalls or other excavations.

3.Drainages. If natural channels are to be affected by the mining operation, then the operator shall take appropriate measures to avoid or minimize environmental damage.

4.Erosion control. Operations shall be conducted in a manner such that sediment from disturbed areas is adequately controlled. The degree of erosion control shall be appropriate for the site-specific and regional conditions of topography, soil, drainage, water quality, or other characteristics.

5.Toxic-forming materials. All toxic-forming or potentially deleterious material shall be safely removed from the site or kept in an isolated condition such that adverse environmental effects are eliminated or controlled.

6.Soils. All available topsoil and subsoil shall be removed, stored, and stabilized. The salvaged topsoil and subsoil must be respread following the backfill and grading of disturbed areas.

7.Concurrent reclamation. During operations, disturbed areas shall be reclaimed as soon as practicable when no longer needed, except to the extent necessary to preserve evidence of mineralization for proof of discovery. Areas which have been disturbed but are not routinely or currently utilized shall be kept in a safe, environmentally stable condition. All reclamation work through seeding must be completed within three years of completion of mining. 43-02-02.4-43. Performance and reclamation standards and requirements.

The land surface of the permit area will be restored as nearly as possible to its original condition unless conflicting with the approved postmining land use. Each reclamation plan must be developed to meet the site-specific characteristics of the mining operation and the site.

1.Most appropriate technology and best management practices. The mining operation and the reclamation plan shall be designed and operated using the most appropriate technology and the best management practices.

2.Contemporaneous reclamation. Contemporaneous reclamation is required to the maximum extent practicable and in a manner that is consistent with the approved reclamation plan. All reclamation work through seeding must be completed within three years of completion of mining.

3.Assure protection. The mining operation and completed reclamation shall meet the following requirements established to assure protection of human health and safety, the environment, wildlife, and domestic animals.

a.Signs, markers, and safeguarding. Measures will be taken to safeguard the public to prevent falls from highwalls or pit edges. Depending on site-specific characteristics, the following measures shall be required:

(1)Posting warning signs in locations near hazardous areas;

(2)Restricting access to hazardous areas;

(3)Marking the permit area boundaries;

(4)Posting a sign at the main entrances giving a telephone number of a person to call in the event of emergencies related to the mine; and (5)Other measures as needed to protect human safety.

b.Wildlife protection. Measures shall be taken to minimize adverse impacts on wildlife and important habitat. Based on site-specific characteristics, the following measures will be required:

(1)Restricting access of wildlife and domestic animals to toxic chemicals or otherwise harmful materials;

(2)Minimizing harm to wildlife habitat during mining; and (3)Reclaiming areas of wildlife habitat if not in conflict with the approved postmining land use.

c.Cultural resources. Cultural resources listed on or eligible for listing on the national register of historic places, and any cemeteries or burial grounds shall be protected until clearance has been granted by the appropriate authority.

d.Hydrologic balance. Operations shall be planned and conducted to minimize change to the hydrologic balance in both the permit and potentially affected areas. If not in conflict with the approved postmining land use, reclamation shall result in a hydrologic balance similar to premining conditions unless nonmining impacts have substantially changed the hydrologic balance.

(1)Operations shall be designed so that nonpoint source surface releases of acid or other toxic substances shall be contained within the permit area, and that all other surface flows from the disturbed area are treated to meet all applicable state and federal regulations.

(2)The disturbed areas shall not contribute suspended solids above background levels, or where applicable the state department of health standards, to ephemeral, intermittent, and perennial streams.

(3)To provide data to determine background levels for surface water entering the permit area, appropriate monitoring shall be conducted on drainages leading into the permit area.

(4)All diversions of overland flow shall be designed, constructed, and maintained to minimize adverse impacts to the hydrologic balance and to assure the safety of the public.

(a)No diversion shall be located so as to increase the potential for landslides.

(b)Unless site-specific characteristics require a different standard which is included in the approved permit, diversions which have watersheds larger than ten acres shall be designed, constructed, and maintained to safely pass the peak runoff from a ten-year, twenty-four-hour precipitation event.

(c)All diversion designs which have watersheds larger than ten acres shall be included in the permit application and certified by a registered professional engineer. Diversion designs shall be kept onsite or otherwise be made available, upon request, to the director for inspection.

(d)When no longer needed, temporary diversions shall be removed and the disturbed area reclaimed.

e.Stream diversions. When streams are to be diverted, the stream channel diversion shall be designed, constructed, and removed in accordance with the following:

(1)Unless site-specific characteristics require different measures to meet the performance standard and are included in the approved permit, the combination of channel, bank, and floodplain configurations shall be adequate to safely pass the peak runoff of a ten-year, twenty-four-hour precipitation event for temporary diversions, or a one-hundred-year, twenty-four-hour precipitation event for permanent diversions;

(2)The design and construction of all intermittent and perennial stream channel diversions shall be certified by a registered professional engineer. As-built drawings shall be completed promptly after construction and be included in the permit application and retained onsite or otherwise made available upon request to the director; and (3)When no longer needed, temporary stream channel diversions shall be removed and the disturbed area reclaimed.

f.Impoundments. If impoundments are required, they shall be designed, constructed, and maintained to minimize adverse impacts to the hydrologic balance and adjoining property and to assure the safety of the public.

(1)Unless site-specific characteristics require different measures to meet the performance standard and are included in the approved permit, impoundments having earthen embankments but not subject to the jurisdiction of the mine safety and health administration or the state department of health shall:

(a)Have a minimum elevation at the top of the settled embankment of two feet above the water surface in the pond with the spillway flowing at the design depth;

(b)Have a top width of the embankment not less than six feet;

(c)Have combined upstream and downstream side slopes of the settled embankment not less than five horizontal: one vertical with neither slope steeper than two horizontal: one vertical. Slopes shall be vegetated or otherwise stabilized to control erosion;

(d)Have the embankment foundation cleared of all vegetative matter, all surfaces sloped to no steeper than one horizontal : one vertical and the entire foundation area scarified;

(e)Have fill material free of vegetative matter and frozen soil;

(f)Have sufficient capacity for sediment storage and have sediment removed when that capacity is reached; and (g)Have spillways provided to safely discharge the peak runoff of a twenty-five-year, twenty-four-hour precipitation event, or an event with a ninety percent chance of not being exceeded for the design life of the structure; or (h)Have other site-specific design criteria for embankments as long as they result in a minimum static safety factor of 1.3 with water impounded to the design level;

(i)Be designed and certified by a registered professional engineer. As-built drawings shall be completed promptly after construction and be retained onsite or otherwise made available upon request to the director; and (j)If necessary for sediment control, be in place before any other disturbance to the watershed for the impoundment.

(2)When no longer required, impoundments shall be graded to achieve positive drainage unless:

(a)The surface estate owner has requested in writing that they be retained;

(b)They are consistent with the approved reclamation plan; and (c)They are appropriate for the postmining land use or the self-sustaining ecosystem.

g.Minimization of mass movement. All temporary stockpiles shall be constructed and maintained to minimize mass movement.

h.Riparian and wetland areas. Disturbance to riparian and wetland areas shall be minimized during mining. Adverse effects to riparian and wetland areas shall be mitigated during reclamation unless the mitigation conflicts with the approved postmining land use.

i.Roads. Roads shall be constructed and maintained to control erosion.

(1)Drainage control structures shall be used as necessary to control runoff and to minimize erosion, sedimentation, and flooding. Culverts or other drainage facilities shall be installed as road construction progresses and shall be capable of safely passing a ten-year, twenty-four-hour precipitation event unless site-specific characteristics indicate a different standard is appropriate and is included in the approved permit. Culverts and drainage pipes shall be constructed and maintained to avoid plugging, collapsing, or erosion.

(2)Roads to be constructed in or across intermittent or perennial streams require site-specific designs to be submitted with the permit application.

(3)Permanent roads must be approved by the surface owner and be consistent with the approved postmining land use.

j.Subsidence control. Underground and in situ solution mining activities shall be planned and conducted, to the extent technologically and economically feasible, to prevent subsidence which may cause material damage to structures or property not owned by the operator.

(1)Solution mining activities near any aquifer that serves as a significant source of water supply to the public water system shall be conducted so as to avoid disruption of the aquifer and consequent exchange of ground water between the aquifer and other strata.

(2)Solution mining activities conducted beneath or adjacent to any perennial stream must be performed in a manner so that subsidence is not likely to cause material damage to streams, water bodies, and associated structures.

k.Explosives. Blasting shall be conducted to prevent injury to persons or damage to property not owned by the operator. Fly rock shall be confined to the permit area. The director may require a detailed blasting plan, or preblast surveys, or may specify blast design limits to control possible adverse effects to structures.

4.Reclamation of surface facilities. The permit area shall be stabilized, to the extent practicable, to minimize future impact to the environment and protect air and water resources. Unless otherwise approved by the department, the reclamation of surface facilities shall include the removal of all buildings, roads, and structures, and the surface restored as nearly as possible to its original condition. Tailings impoundments and ponds must be reclaimed and filled in and respread with topsoil and subsoil. All grading, backfilling, and topographic reconstruction must control erosion and sedimentation, protect areas outside the affected land from slides or other damage, and minimize the need for long-term maintenance.

Measures must be taken to reduce, to the extent practicable, the formation of acid and other toxic drainage that may otherwise occur following closure to prevent releases that cause federal or state standards to be exceeded. Nonpoint source surface releases for acid or other toxic substances shall be contained within the permit area.

Ponds and impoundment reclamation must meet the following requirements:

a.Pond sludge must be chemically characterized to determine whether further treatment is necessary before disposal. Sludge must be removed for disposal at on offsite permitted solid waste facility or buried and covered onsite in a solid waste facility permitted in accordance with the applicable solid waste rules in article 33-20; and

b.Geomembranes must be removed from impoundments, unless it is demonstrated to the department's satisfaction that they will serve a useful function consistent with the approved postmining land use. The geomembrane material must be disposed of in a permitted landfill or may be disposed of onsite only if the operator first secures a solid waste permit in compliance with article 33-20.

5.Topsoil and subsoil. The operator shall take measures to remove and save all available topsoil and subsoil and protect it from erosion or contamination and assure that it is in a usable condition for sustaining vegetation when needed. The following requirements shall be met unless site-specific characteristics mandate different requirements and those requirements are included in the approved permit.

a.Topsoil and subsoil shall be sampled and analyzed for vegetation establishment suitability:

(1)Sample spacing and interval shall be based on site-specific materials; and (2)Suitability will be identified by analysis based on site-specific materials.

b.Revegetation must be a component of the reclamation plan and all available topsoil and subsoil must be salvaged and replaced on disturbed areas.

c.Where direct distribution of topsoil or subsoil is not possible, it shall be stockpiled separately in a manner to prevent the loss of the resource.

d.Topsoil and subsoil shall be distributed in a manner to establish and maintain vegetation, consistent with the approved permit.

e.After distribution, topsoiled and subsoiled areas shall be stabilized to protect loss of the resource.

f.Where topsoil has been stockpiled for more than one year, the operator may be required to conduct analyses to determine if amendments are necessary.

6.Erosion control. Reclamation of disturbed lands must result in a condition that minimizes erosion. Revegetated lands must not contribute suspended solids above background levels, or where applicable the state department of health standards, to streamflow of intermittent and perennial streams. Acceptable practices to control erosion include the following:

a.Stabilizing disturbed areas through land shaping, berming, or grading to final contour;

b.Minimizing reconstructed slope lengths and gradients;

c.Diverting runoff;

d.Establishing vegetation;

e.Regulating channel velocity of water;

f.Lining drainage channels with rock, vegetation, or other geotechnical materials; and

g.Mulching.

7.Revegetation. Revegetated lands must meet the following standards:

a.Revegetation success for a return as near as possible to original condition shall be determined through comparison of ground cover, productivity, and diversity and shall be made on the basis of the following approved reference areas:

(1)Foliage or basal cover and productivity of living perennial plants of the revegetated area shall be established equal to ninety percent of the reference area or equal to the approved revegetation standard using scientifically valid sampling techniques;

(2)Diversity of plant life forms (woody plants, grasses, and forbs) shall consider what is reasonable based on the physical environment of the reclaimed area; and (3)Woody plant species shall be established to the approved density standard.

b.For areas for which the approved postmining land use is for wildlife habitat or forest land, success of vegetation shall be determined on the basis of tree or shrub stocking (density) and ground cover.

(1)The ground cover of living perennial plants shall be equal to ninety percent of the native ground cover of the reference area or other approved standard and shall be adequate to minimize erosion.

(2)Tree density for forest land shall have establishment rates of plant species equal to ninety percent of the approved reference area or other approved standard and shall be adequate to minimize erosion.

(3)If wildlife habitat is to be the postmining land use, the operator shall select and use plant species on the reclaimed areas based on the following criteria:

(a)Their proven nutritional value for fish and wildlife;

(b)Their uses as cover and security for wildlife;

(c)Their ability to support and enhance fish and wildlife habitat; and (d)Distribute plant life forms to maximize benefits of edge effect, cover, and other benefits for fish and wildlife.

c.Revegetation for other postmining land shall be consistent with the approved postmining land use. Site-specific standards may include standards for foliar or basal cover, production, and diversity and will be included in the approved permit. 43-02-02.4-44. Report of water injected.

The operator of each and every injection well shall, on or before the tenth day of the second month succeeding the month in which injection occurs, file with the director the amount of liquid injected, the composition of the liquid, and the source thereof upon approved computer sheets no larger than eight and one-half by eleven inches [21.59 by 27.94 centimeters]. The report shall be signed by both the person responsible for the report and the person witnessing the signature. The printed name and title of both the person signing the report and the person witnessing the signature shall be included. 43-02-02.4-45. Report of production.

The operator of a mine shall, on or before the tenth day of the second month succeeding the month in which production occurs, file with the director the amount of production made by the mine upon form 5-sm or approved computer sheets no larger than eight and one-half by eleven inches [21.59 by 27.94 centimeters]. The report shall be signed by both the person responsible for the report and the person witnessing the signature. The printed name and title of both the person signing the report and the person witnessing the signature shall be included.

Production data submitted to the director shall be kept confidential for a period of one year when so requested by the operator. Such period may be further extended upon approval by the commission. 43-02-02.4-46. Reports of natural brine produced.

A person who is producing natural brine shall be required by the director to report annually, within sixty days after the end of the calendar year of production, the amount of natural brine produced during the calendar year of production, unless an extension of time is granted by the director. The reports shall be signed by the person who is producing brine on forms prescribed by, or acceptable to, the director. 43-02-02.4-47. Solution mining - Reporting.

An operator shall control cavity shape during solution mining of bedded salt.

An operator who is solution mining shall report annually, within sixty days after the end of the calendar year, the amount of soluble mineral or rock removed and the volumes of fluids injected into and removed from each cavity.

The report shall be signed by both the person responsible for the report and the person witnessing the signature. The printed name and title of both the person signing the report and the person witnessing the signature shall be included. 43-02-02.4-48. Rock profile determination.

The operator shall determine the cavity roof position not less than biennially. Generally accepted wireline logging methods shall be utilized. The results of the determination shall be filed with the director not more than sixty days after completion and shall include all wireline logs run. 43-02-02.4-49. Books and records to be kept to substantiate reports.

All operators within North Dakota shall make and keep appropriate books and records for a period not less than six years covering their operations in North Dakota from which they may be able to make and substantiate the reports required by this chapter. 43-02-02.4-50. Additional information may be required.

This chapter shall not be taken or construed to limit or restrict the authority of the commission to require the furnishing of such additional reports, data, or other information relative to production or products as may appear to be necessary or desirable, either generally or specifically, for the prevention of waste, protection of correlative rights, and the conservation of natural resources.

Chapter 43-02-02.5 Exploration and Production of Critical Minerals in Coal-Bearing Formations

N.D. Admin. Code 43-02-02.5 Exploration and Production of Critical Minerals in Coal-Bearing Formations

CHAPTER 43-02-02.5

EXPLORATION AND PRODUCTION OF CRITICAL MINERALS IN COAL-BEARING

FORMATIONS

Section 43-02-02.5-01Definitions 43-02-02.5-02Scope of Chapter 43-02-02.5-03Enforcement of Laws, Rules, and Regulations 43-02-02.5-04United States Government Leases 43-02-02.5-05Forms Upon Request 43-02-02.5-06Authority to Cooperate with Other Agencies 43-02-02.5-07Organization Reports 43-02-02.5-08Record of Permits 43-02-02.5-09Exploration Permit 43-02-02.5-10Exploration Bond 43-02-02.5-11Processing Facility Permit 43-02-02.5-12Processing Facility Bond 43-02-02.5-13Mining Permit 43-02-02.5-14Public Availability of Permit Application Information 43-02-02.5-15Confining of Waters to Their Original Strata 43-02-02.5-16Method of Plugging 43-02-02.5-17Testholes to Be Used for Fresh Water 43-02-02.5-18Inspections 43-02-02.5-19Basic Data 43-02-02.5-20Exploration Reports 43-02-02.5-21Report of Production 43-02-02.5-22Commingled Production 43-02-02.5-23Investigative Powers 43-02-02.5-24Additional Information May Be Required 43-02-02.5-25Books and Records to Be Kept to Substantiate Reports 43-02-02.5-26Application for Hearing 43-02-02.5-27Hearings - Proceedings 43-02-02.5-28Investigatory Hearings 43-02-02.5-29Official Record 43-02-02.5-30Petitions and Oral Arguments Prohibited 43-02-02.5-31Notice of Order 43-02-02.5-32Service and Filing 43-02-02.5-33Designation of Examiners 43-02-02.5-34Powers and Duties of Examiner 43-02-02.5-35Report of Examiner 43-02-02.5-36Commission Order from Examiner Hearing 43-02-02.5-37Prehearing Motion Practice 43-02-02.5-01. Definitions.

The terms used throughout this chapter have the same meaning as in North Dakota Century Code

chapter 38-12, except:

1."Certified mail" means a form of service by the United States postal service, federal express, Pitney Bowes, or other commercial nationwide delivery service that provides the mailer with a document showing the date of delivery or refusal to accept delivery.

2."Commission" means the industrial commission.

3."Director" means the director of the department of mineral resources of the industrial commission.

4."Log or well log" means a systematic, detailed, and accurate record of one or more properties as a function of depth in an open or cased well bore. The term includes geophysical, petrophysical, image, or engineered or composite logs, or other well bore measurements acquired while drilling or by wireline operations recorded in paper or digital format.

5."Mined area" means the area where coal has been mined for its critical mineral content from within the boundaries of a public service commission-approved mine permit within one calendar year.

6."Processing facility" means a facility that extracts critical minerals from coal-bearing formations.

7."Testhole" means a hole drilled for the purpose of gathering information on subsurface minerals.

8."Waste" means:

a.Physical waste;

b.Operations that cause or tend to cause unnecessary or excessive surface loss; or

c.Operations that do not recover all the mineral being mined that is technically and economically possible. 43-02-02.5-02. Scope of chapter.

This chapter contains general rules of statewide application which have been adopted by the commission to conserve the natural resources of North Dakota, prevent waste, and provide for operation in a manner as to protect correlative rights of all owners of subsurface minerals. Special rules, regulations, and orders may be issued as required and must prevail against general rules, regulations, and orders if there is a conflict. If this chapter does not conflict with special rules, this

chapter applies. The commission may grant exceptions to this chapter, after due notice and hearing, if exceptions result in the prevention of waste and operation in a manner to protect correlative rights. 43-02-02.5-03. Enforcement of laws, rules, and regulations.

The commission and its agents, representatives, and employees shall enforce all rules and statutes of North Dakota relating to the exploration, development, and production of critical minerals. However, it is the responsibility of all owners or operators to obtain information pertaining to the regulation of subsurface minerals before operations begin. 43-02-02.5-04. United States government leases.

The commission recognizes all persons exploring for, producing, or processing critical minerals on United States government land or for United States government minerals shall comply with federal regulations and applicable state rules and regulations. 43-02-02.5-05. Forms upon request.

Forms for written notices, requests, and reports required by the commission must be furnished upon request. The forms must be of the nature prescribed by the commission covering proposed work, work in progress, and the results of completed work. 43-02-02.5-06. Authority to cooperate with other agencies.

The commission may enter arrangements with state and federal government agencies, industry committees, and individuals with respect to special projects, services, and studies relating to critical minerals. 43-02-02.5-07. Organization reports.

A person acting as principal or agent for another or independently engaged in the drilling for, or in the production, storage, transportation, refining, reclaiming, treating, marketing, or processing of the critical minerals in North Dakota immediately shall file with the state geologist the name under which business is being conducted and operated; the name and post-office address of the person; the business or businesses in which the person is engaged; the plan of organization, and in case of a corporation, the law under which it is chartered; and the names and post-office addresses of any persons acting as trustees, together with the names and post-office addresses of any officials on an organization report. If the business is conducted under an assumed name, the organization report shall show the names and post-office addresses of all owners in addition to the other information required. A new organization report must be filed when and if there is a change in any of the information contained in the report. 43-02-02.5-08. Record of permits.

The state geologist shall maintain an official permit list, including:

1.The name of the permitholder;

2.The permit number;

3.The date the permit was issued; and

4.The location (county) of the permit. 43-02-02.5-09. Exploration permit.

1.A permit is required before commencement of operations for the exploration and evaluation of critical minerals. A permit must be granted for one year upon receipt of a permit application on a form provided by the commission, the furnishing of a bond as set out in this chapter, and the payment of a fee of one hundred dollars per permit. A permit is valid for one permit area only.

2.A critical minerals exploration permit is not required within a coal mine permit boundary, but a permit from the public service commission is required. However, ownership and all exploratory data used to determine critical mineral concentrations must be provided to the commission.

3.Coal may not be extracted for commercial sale during a critical mineral exploration operation.

Coal may not be extracted except for cores and samples necessary for testing and analysis.

The removal of more than two hundred fifty tons [226.80 metric tons] of coal from an area is considered a surface coal mining operation and is subject to the requirements of North Dakota Century Code chapter 38-14.1 and the regulations of the public service commission promulgated under North Dakota Century Code chapter 38-14.1.

4.The permit application must include:

a.The name, address, and telephone number of the person seeking to explore.

b.The name, address, and telephone number of the representative who will be present at and responsible for conducting the exploration activities.

c.A precise description of the exploration area.

d.A statement of the period of intended exploration.

e.A description of the practices proposed to be followed to protect the environment from adverse impacts as a result of the exploration activities.

f.Any other information required by the commission.

General Authority: NDCC 38-12-03

Law Implemented: NDCC 38-12-03 43-02-02.5-10. Exploration bond.

1.A person engaged in critical mineral exploration and evaluation, or who proposes to do so, shall submit to the commission and obtain its approval of a surety bond or cash bond. An alternate form of security may be approved by the commission after notice and hearing, as provided by law. A bond is required for each permit area. The bond must be in the amount of one hundred dollars for each testhole drilled in the permit area. Each surety bond must be executed by a responsible surety company authorized to transact business in the state of North Dakota. A blanket bond in the amount of ten thousand dollars, conditioned as above provided, may be submitted to cover any number of testholes drilled in one or more permit areas. The blanket bond shall cover all permits issued in one year commencing on the date the first permit covered by the bond is issued.

2.A person providing a blanket bond in lieu of several individual bonds is required to comply with the rules, regulations, and orders of the commission in the same manner as if the person had provided several individual bonds. Violation shall result in forfeiture of the blanket bond in its entirety, if the violation would have resulted in forfeiture had the action in question been covered by an individual bond.

3.For the purposes of the commission the bond required is a performance bond and a plugging bond and is to endure up to and including receipt by the state geologist of all basic exploration data required by law and approved plugging of all holes drilled.

4.The commission shall advise in writing the principal and sureties on a surety bond as to whether the provisions of statutes and rules have been satisfied and liability under the bond may be formally terminated.

5.The state geologist may act for the commission as to all matters within this section.

6.A state or federal agency engaged in critical mineral exploration or evaluation is exempt from providing the bond. 43-02-02.5-11. Processing facility permit.

1.A processing facility permit application is required before commencement of operations to create or construct a processing facility. The application for a processing facility permit must be filed with the director, together with a permit fee. The amount of the permit fee is determined by the state geologist based upon the cost for the commission to review, investigate, and process the application. Activity may not commence until the application is approved and a permit is issued by the director. Upon successful review of the application, the amount of the facility bond is determined. The permit application may not be approved until the facility bond is in effect.

2.Permit applications for a processing facility shall address the following:

a.Identification of interests, including:

(1)The name and address of the operator responsible for the processing facility operations and reclamation of the site.

(2)The names and addresses of the surface landowners of all land within the permit boundary of the processing facility.

b.Project location description and maps plotted at a scale to accurately identify locational landmarks and operational details, including:

(1)A legal description of the proposed processing facility permit area.

(2)The general location as shown on a topographic map that gives the location of the following: perennial, intermittent, and ephemeral streams; springs and seeps; wetlands, riparian areas, lakes and other water bodies; residences, businesses, and other structures; existing and proposed roads; other access routes; support facilities; cemeteries; burial grounds; cultural resources listed on the national register of historic places; electrical transmission and communication lines; pipelines; and oil, gas, and water wells on and within one-half mile [.80 kilometer] of the permit area.

(3)An operations map that identifies:

(a)All buildings, structures, tanks, pits, vats, pipelines, access roads, and other types of infrastructure; a surface facilities map that identifies the locations of buildings; processing equipment; roads; underground utilities; power lines; proposed drainage control structures; the location of topsoil and subsoil storage areas, if warranted; tailings or processed waste facilities; and solid and liquid wastes and wastewater discharge treatment and containment facilities.

(b)Any dikes, berms, or other structures that are meant to contain processing fluids onsite.

c.A brief narrative description of the proposed processing facility plan of operation, including:

(1)A general description and list of the critical minerals sought and the methods of extraction. Any chemicals to be used onsite must be identified, where and how they will be stored, and where and how they will be disposed. Any forms of disposal shall comply with the rules and regulations of the North Dakota department of environmental quality.

(2)A geological cross-section across the permit application area to a depth of one hundred feet [30.48 meters].

(3)An estimate of depth to ground water and general water chemistry.

(4)Estimated width and length of any new roads to be constructed.

(5)An estimate of the total number of surface acres to be disturbed by the processing facility.

(6)A description of the plans for any structures to be used for managing runoff from the site, if warranted.

(7)A contingency plan to mitigate impacts to wildlife if there is an emergency or accidental discharge of toxic substances that may impact wildlife.

(8)A description of measures to be undertaken to control sedimentation from the permit area and a plan for the monitoring of nonpoint source sediment pollution from the disturbed area.

d.The operator shall provide a general narrative description identifying potential surface and subsurface impacts. At a minimum, this description shall include:

(1)Projected impacts to surface and ground water systems;

(2)Actions proposed to mitigate any impacts; and (3)A plan for the management of waste streams in accordance with chapters 33.1-16-01, 33.1-20-01.1, 33.1-20-09, and 33.1-25-01, as applicable.

e.A person controlling or operating any processing facility shall notify verbally the director within twenty-four hours after discovery of any fire, leak, spill, or release of fluid. If the incident occurs or travels offsite of a facility, the person responsible for proper notification shall notify the surface owners upon whose land the incident occurred or traveled within twenty-four hours after the discovery of the incident.

f.An application must include a reclamation plan, including maps or drawings as necessary, consisting of a narrative description of the proposed reclamation, including:

(1)A detailed description of any surface facilities that are proposed to be left at closure, including buildings, utilities, roads, pads, ponds, pits, and surface equipment.

(2)A description of the treatment, location, and disposition of any toxic-forming or acid-forming materials generated and left onsite, including a map showing the location of the materials upon the completion of reclamation.

g.The reclamation plan must be updated as necessary and submitted for approval prior to the commencement of final reclamation activities.

h.Unless otherwise approved in the reclamation plan, all buildings and infrastructure must be removed. All disturbed lands must be reclaimed to a condition consistent with prior land use and productive capacity.

3.The commission shall review the facility permit at least once every five years to determine whether it should be amended, modified, or revoked.

General Authority: NDCC 38-12-03

Law Implemented: NDCC 38-12-03 43-02-02.5-12. Processing facility bond.

1.Before any person receives a permit to conduct processing facility operations for critical minerals, the person shall submit to the commission and obtain its approval of a surety bond executed by a responsible surety company authorized to transact business in North Dakota or a cash bond. An alternate form of security may be approved by the commission after notice and hearing, as provided by law. The operator of a processing facility must be the principal on the bond covering the activity. The amount of the bond must be specified by the commission and based upon the estimated reclamation costs.

2.Bonds must be conditioned upon full compliance with North Dakota Century Code chapter 38-12, and all administrative rules and orders of the commission, and continues until any of the following occurs:

a.The lands disturbed by any method of processing of critical minerals have been restored and approved by the director.

b.The liability on the bond has been transferred to another bond and such transfer has been approved by the commission.

3.Transfer of property does not release the bond. In case of transfer of property or other interest in a processing facility and the principal desires to be released from the bond covering the facility:

a.The principal shall notify the director in writing of all proposed transfers of property at least thirty days before the closing date of the transfer. The director may waive this requirement for good cause.

b.The principal shall submit to the commission on a transfer form reciting that a certain property or properties, describing each by quarter-quarter, section, township, and range, is to be transferred to a certain transferee, naming the transferee, for the purpose of ownership or operation. The date of assignment or transfer must be stated and the form signed by a party duly authorized to sign on behalf of the principal.

c.On the transfer form the transferee shall recite the following: "The transferee has read the foregoing statement and accepts such transfer and the responsibility of such property under the transferee's processing facility bond." Such acceptance must be signed by a party authorized to sign on behalf of the transferee and the transferee's surety.

d.If the commission approves the transfer and acceptance and accepts it under the transferee's bond, the transferor is released from the responsibility of site reclamation.

e.The transferee (new operator) of any processing facility is responsible for the site reclamation of any such property. For that purpose, the transferee shall submit a new bond or, in the case of a surety bond, produce the written consent of the surety of the original or prior bond that the surety's responsibility shall continue. The original or prior bond may not be released as to the reclamation responsibility of any such transferor until the transferee submits to the commission an acceptable bond to cover the facility. All liability on bonds shall continue until all structures are removed and the reclamation of the property is completed and approved.

4.The director periodically shall review the amount of bond and, with the commission's approval, may require adjustments to the amount of bond to reflect inflationary increases or increases in the anticipated costs of reclamation. An operator may request a hearing to dispute an adjustment.

5.The commission shall advise, in writing, the principal and any sureties on any bond as to whether the reclamation is approved. If approved, liability under the bond may be formally terminated upon receipt of a written request by the principal. The request must be signed by an officer of the principal or a person authorized to sign for the principal.

6.The director may act for the commission as to all matters within this section, except requests for alternative forms of security, which may only be approved by the commission.

7.The commission may refuse to accept a bond if the operator or surety company has failed in the past to comply with statutes, rules, or orders; if a civil or administrative action brought by the commission is pending against the operator or surety company; or for other good cause. 43-02-02.5-13. Mining permit.

Mining of noncoal rock for its critical mineral content shall follow chapter 43-02-02.2, 43-02-02.3, or 43-02-02.4, as applicable. 43-02-02.5-14. Public availability of permit application information.

1.Except as provided in subdivisions a, b, and c, all information submitted to the commission with a permit application for critical mineral exploration is available for public inspection and copying at the office of the state geologist.

a.The state geologist may not make information submitted with a critical mineral exploration permit application available for public inspection if the person submitting it requests in writing, at the time of permit application submission, that it not be disclosed and the state geologist determines that the information is confidential. However, the information shall remain confidential only for the time period specified in North Dakota Century Code section 38-12-02.

b.The state geologist shall determine permit application information is confidential if it concerns trade secrets or is privileged commercial or financial information that relates to the competitive rights of the person intending to conduct critical mineral exploration.

c.Information requested to be held as confidential under this subsection may not be made publicly available until after proper notice and hearing before the commission.

2.The director may withhold specific information in a processing facility application if releasing the information would reveal trade secrets or in other ways cause the applicant financial harm.

3.The permitholder may waive the holder's right to confidentiality by providing written notice of the waiver to the state geologist. 43-02-02.5-15. Confining of waters to their original strata.

During the drilling of any testhole, all fresh waters and waters of present or probable value for domestic, commercial, or stock purposes encountered must be confined to their respective strata and must be adequately protected by methods approved by the state geologist. Special precautions must be taken in drilling and abandoning of testholes to guard against any loss of artesian water from the strata in which it occurs, and to prevent contamination of artesian water by objectionable water. 43-02-02.5-16. Method of plugging.

1.Before any testhole is abandoned, all of the cuttings possible must be returned to the testhole, and it must be plugged in a manner to prevent the intrusion of any foreign material. Cuttings not returned to the hole must be spread at the surface, if approved by the landowner, or properly disposed of off the testhole site, if approved by the owner of the disposal site. The plugging must be accomplished immediately when all desired information has been obtained.

2.If a testhole penetrates water-bearing sands, it must be plugged with cement or some other method approved by the state geologist, in a manner to permanently confine the water to its original stratum. 43-02-02.5-17. Testholes to be used for fresh water.

1.If a testhole to be plugged may be used safely as a freshwater well and such utilization is desired by the landowner, the testhole need not be filled above a sealing plug set below the freshwater aquifer provided written authority and assumption of liability for the use and plugging is secured from the landowner and filed with the state geologist. The person conducting the critical mineral exploration must be relieved of that person's responsibility under this chapter.

2.The landowner assuming ownership and liability for the testhole shall comply with the rules for water well construction and water well pump installation pursuant to North Dakota Century Code chapter 43-35. 43-02-02.5-18. Inspections.

1.The state geologist or the state geologist's representative shall have access to all drilling or exploration sites, mines, and processing facilities regulated under this chapter for the purpose of inspection and sampling. The state geologist may require the aid of the permitholder if the state geologist finds such aid necessary and requests such aid.

2.If samples are to be collected by the state geologist, details relating to the starting date of the collection of such samples and the drill site locations must be worked out between the state geologist or the state geologist's agents and the permitholder or the permitholder's agents before the starting date of collection. 43-02-02.5-19. Basic data.

1.Basic data developed by or for the person conducting critical mineral exploration or evaluation, consisting of testhole locations; testhole elevations; total depths; driller's logs; radioactivity, resistivity, or other types of electrical or mechanical logs; laboratory analyses; or any other pertinent data collected during the project must be delivered free of charge to the state geologist.

2.If requested by the operator, the data submitted must be confidential for a period of one year commencing on the expiration date of the permit. The period may be extended further upon approval of the commission. As long as the operator is exploring, developing, or producing critical minerals, the basic data may remain confidential. The commission and the state geologist shall have access to all confidential data. The director may release confidential completion and production data to health care professionals; emergency responders; and state, federal, or tribal environmental and public health regulators, if the state geologist deems it necessary to protect the public's health, safety, and welfare.

3.Sample cuts, portions of cores not required for analysis, and core analyses developed by or for the person conducting the critical mineral exploration or evaluation also must be submitted free of cost to the state geologist, if requested. 43-02-02.5-20. Exploration reports.

1.Quarterly progress reports listing locations of testholes completed and plugged must be filed by the twenty-fifth day of January, April, July, and October by all permitholders. If no drilling occurred during the quarter, a report so stating must be filed.

2.Completion reports also must be filed upon completion of the exploration or evaluation, or upon the expiration of the permit, whichever occurs first, by all permitholders. The completion reports shall include all progress on exploration and evaluation and any other information requested by the state geologist. 43-02-02.5-21. Report of production.

1.On or before the first day of the second month succeeding the month in which production occurs, the operator of a processing facility shall file with the state geologist a report containing the following information:

a.The volume of coal that is processed;

b.The volume and chemical makeup of the critical mineral concentrate;

c.The volume of the concentrate shipped; and

d.The shipping destination.

2.The report must be signed by the person responsible for the report and the person witnessing the signature. The printed name and title of both the person signing the report and the person witnessing the signature must be included.

3.Production data submitted to the state geologist must be kept confidential for a period of one year if so requested by the operator. The period may be extended further upon approval by the commission. The commission may share production data with other state agencies, upon request, for purposes of administering statutory duties related to mineral ownership, royalty oversight or trust administration. The other state agencies shall not share the data with any other entity and shall protect the confidentiality of any such production data subject to the requirements of North Dakota Century Code chapter 44-04. 43-02-02.5-22. Commingled production.

If two or more separately owned tracts are embraced within a mined area, or if there are separately owned interests in all or a part of the mined area, the critical minerals must be commingled by the operator for the purpose of allocating production and payment of royalties. Each mined area shall afford to the owner of each tract or interest within the mined area the opportunity to recover or receive, without unnecessary expense, the owner's equitable share based on the volume of mined coal.

General Authority: NDCC 38-12-06

Law Implemented: NDCC 38-12-06 43-02-02.5-23. Investigative powers.

Upon receipt of a written complaint from a surface owner or lessee; royalty owner; mineral owner; or local, state, or federal official alleging a violation of the subsurface mineral conservation statutes or a

rule, regulation, or order of the commission, the director shall reply within reasonable time in writing to the person who submitted the complaint stating an investigation of the complaint will be made or the reason such investigation may not be made. The person who submitted the complaint may appeal the decision of the director to the commission. The director also may conduct investigations on the director's own initiative or at the direction of the commission. If, after such investigation, the director affirms cause for complaint exists, the director shall report the results of the investigation to the person who submitted the complaint, if any, to the person who was the subject of the complaint, and to the commission. The commission shall institute legal proceedings, in its discretion, it believes necessary to enjoin further violations. 43-02-02.5-24. Additional information may be required.

This chapter may not be taken or construed to limit or restrict the authority of the commission to require the furnishing of additional reports, data, or other information relative to exploration, production, or processing as may appear to be necessary or desirable, generally or specifically, for the prevention of waste, protection of correlative rights, and the conservation of natural resources. 43-02-02.5-25. Books and records to be kept to substantiate reports.

All producers within North Dakota shall make and keep appropriate books and records for a period not less than six years covering their operations in North Dakota from which they may be able to make and substantiate the reports required by this chapter. 43-02-02.5-26. Application for hearing.

In any proceeding instituted upon application, the application must be signed by the applicant or by the applicant's attorney. An application shall state:

1.The name and general description of the common source or sources of supply affected by the order, rule, or regulation sought, if any, unless the entire state is affected, in which event the application shall so state, and the statement shall constitute sufficient description; and

2.Briefly the general nature of the order, rule, or regulation sought in the proceedings. 43-02-02.5-27. Hearings - Proceedings.

1.Except as more specifically provided in North Dakota Century Code section 38-12-04, the rules of procedure established in subsection 1 of North Dakota Century Code section 28-32-21 apply to proceedings involving a complaint and a specific-named respondent.

2.For proceedings that do not involve a complaint and a specific-named respondent, the commission shall give at least fifteen days' notice, except in an emergency, of the time and place of hearing by one publication of notice in a newspaper of general circulation in Bismarck, North Dakota, and in a newspaper of general circulation in the county where the land or some part affected is situated, unless in some particular proceeding a longer period of time or a different method of publication is required by law, it shall prevail. The notice shall issue in the name of the commission and shall conform to the other requirements provided by law.

3.If an emergency is found by the commission to exist, which in its judgment requires the making of a rule or order without first having a hearing, the emergency rule or order shall have the same validity as if a hearing with respect to the same had been held after notice. The emergency rule or order permitted by this section shall remain in force no longer than fifteen days from its effective date, and in any event, it shall expire when the rule or order made after due notice and hearing with respect to the subject matter of the emergency rule or order becomes effective.

4.A person moving for a continuance of a hearing, and who is granted a continuance, shall submit a twenty-five dollar fee to the commission, or if the cost of republication exceeds fifty dollars, the commission may bill the applicant to pay the cost of republication of notice of the hearing. 43-02-02.5-28. Investigatory hearings.

The commission may hold investigatory hearings upon the institution of a proceeding by application or by a motion of the commission. Notice of the hearing must be served upon all parties personally or by certified mail at least five days before the hearing. 43-02-02.5-29. Official record.

The evidence in each case heard by the commission, unless specifically excluded by the hearing examiner, includes all subsurface mineral basic data and production records on file with the commission.

Any interested party may submit written comments on or objections to the application before the hearing date. Submissions must be received no later than five p.m. on the last business day before the hearing date and may be part of the record in the case if allowed by the hearing examiner. Settlement negotiations between parties to a contested case are only admissible as governed by North Dakota Century Code section 28-32-24, although the hearing examiner may strike such testimony from the record for good cause.

General Authority: NDCC 28-32-06

Law Implemented: NDCC 28-32-06 43-02-02.5-30. Petitions and oral arguments prohibited.

Petitions for review of a recommended order and oral arguments following issuance of a recommended order and pending issuance of a final order are not allowed. 43-02-02.5-31. Notice of order.

The commission may give notice of an order and findings and conclusions upon which it is based to all parties if it files an affidavit of service indicating upon whom the order was served. 43-02-02.5-32. Service and filing.

All pleadings, notices, written motions, requests, petitions, briefs, and correspondence to the commission or commission employees from a party, or vice versa, relating to a proceeding after its commencement must be filed with the director and entered into the commission's official record of the procedure provided the record is open at the time of receipt. All parties shall receive copies upon request of any evidence in the record of the proceedings. The commission may charge for the actual cost of providing copies of evidence in the record. Unless otherwise provided by law, filing is complete when the material is entered into the record of the proceeding. 43-02-02.5-33. Designation of examiners.

The commission by motion may designate and appoint qualified individuals to serve as examiners.

The commission may refer any matter or proceeding to any legally designated and appointed examiner. 43-02-02.5-34. Powers and duties of examiner.

The commission by motion may limit the powers and duties of an examiner in a particular case to the issues or performance of acts the commission deems expedient. However, subject only to a limitation ordered by the commission, the examiner to whom a matter or proceeding is referred under this chapter may hold hearings on the matter or proceeding in accordance with and pursuant to this

chapter. The examiner shall have the power to regulate proceedings before the examiner and to perform acts and take measures necessary or proper for the efficient and orderly conduct of the hearing, including ruling on prehearing motions, the swearing of witnesses, and receiving of testimony and exhibits offered in evidence, subject to any objections imposed, and shall cause a complete record of the proceedings to be made and retained. 43-02-02.5-35. Report of examiner.

Upon the conclusion of a hearing before an examiner, the examiner promptly shall consider the proceedings in the hearing, and based upon the record of the hearing, the examiner shall prepare a report and recommendations for the disposition of the matter or proceeding by the commission. The report and recommendations must be accompanied by a proposed order or be in the form of a proposed order, and be submitted to the commission. 43-02-02.5-36. Commission order from examiner hearing.

After receipt of the report and recommendation of the examiner, the commission shall enter its order disposing of the matter or proceeding. 43-02-02.5-37. Prehearing motion practice.

In a matter pending before the commission, all prehearing motions must be served by the moving party upon all parties affected by the motion. Service must be upon a party unless a party is represented by an attorney, in which case service must be upon the attorney. Service must be made by delivering a copy of the motion and supporting papers in conformance with one of the means of service provided for in rule 5(b) of the North Dakota Rules of Civil Procedure. Proof of service must be made as provided in rule 4 of the North Dakota Rules of Civil Procedure or by certificate of an attorney showing service has been made. Proof of service shall accompany the filing of a motion. Any motion filed without proof of service is not properly before the commission.

Chapter 43-02-03 Oil and Gas Conservation

N.D. Admin. Code 43-02-03-01 Definitions

The terms used throughout this chapter have the same meaning as in North Dakota Century Code

chapter 38-08 except:

1."Adjusted allowable" means the allowable production a proration unit receives after all adjustments are applied.

2."Allocated pool" is one in which the total oil or natural gas production is restricted and allocated to various proration units therein in accordance with proration schedules.

3."Allowable production" means that number of barrels of oil or cubic feet of natural gas authorized to be produced from the respective proration units in an allocated pool.

4."Barrel" means forty-two United States gallons [158.99 liters] measured at sixty degrees Fahrenheit [15.56 degrees Celsius] and fourteen and seventy-three hundredths pounds per square inch absolute [1034.19 grams per square centimeter].

5."Barrel of oil" means forty-two United States gallons [158.99 liters] of oil after deductions for the full amount of basic sediment, water, and other impurities present, ascertained by centrifugal or other recognized and customary test.

6."Bottom hole or subsurface pressure" means the pressure in pounds per square inch gauge under conditions existing at or near the producing horizon.

7."Bradenhead gas well" means any well capable of producing gas through wellhead connections from a gas reservoir which has been successfully cased off from an underlying oil or gas reservoir.

8."Casinghead gas" means any gas or vapor, or both gas and vapor, indigenous to and produced from a pool classified as an oil pool by the commission.

9."Certified or registered mail" means any form of service by the United States postal service, federal express, Pitney Bowes, and any other commercial, nationwide delivery service that provides the mailer with a document showing the date of delivery or refusal to accept delivery.

10."Commercial injection well" means one that only receives fluids produced from wells operated by a person other than the principal on the bond.

11."Common purchaser for natural gas" means any person now or hereafter engaged in purchasing, from one or more producers, gas produced from gas wells within each common source of supply from which it purchases, for processing or resale.

12."Common purchaser for oil" means every person now engaged or hereafter engaging in the business of purchasing oil in this state.

13."Common source of supply" is synonymous with pool and is a common accumulation of oil or gas, or both, as defined by commission orders.

14."Completion" means an oil well shall be considered completed when the first oil is produced through wellhead equipment into tanks from the ultimate producing interval after casing has been run. A gas well is considered complete when the well is capable of producing gas through wellhead equipment from the ultimate producing zone after casing has been run. A dry hole is considered complete when all provisions of plugging are complied with as set out in this chapter.

15."Condensate" means the liquid hydrocarbons recovered at the surface that result from condensation due to reduced pressure or temperature of petroleum hydrocarbons existing in a gaseous phase in the reservoir.

16."Cubic foot of gas" means the volume of gas contained in one cubic foot [28.32 liters] of space and computed at a pressure of fourteen and seventy-three hundredths pounds per square inch absolute [1034.19 grams per square centimeter] at a base temperature of sixty degrees Fahrenheit [15.56 degrees Celsius].

17."Director" means the director of oil and gas of the industrial commission, the assistant director of oil and gas of the industrial commission, and their designated representatives.

18."Enhanced recovery" means the increased recovery from a pool achieved by artificial means or by the application of energy extrinsic to the pool, which artificial means or application includes pressuring, cycling, pressure maintenance, or injection to the pool of a substance or form of energy but does not include the injection in a well of a substance or form of energy for the sole purpose of:

a.Aiding in the lifting of fluids in the well; or

b.Stimulation of the reservoir at or near the well by mechanical, chemical, thermal, or explosive means.

19."Exception well location" means a location which does not conform to the general spacing requirements established by the rules or orders of the commission but which has been specifically approved by the commission.

20."Flow line" means a pipe or conduit of pipes used for the transportation, gathering, or conduct of a mineral from a wellhead to a separator, treater, dehydrator, tank battery, or surface reservoir.

21."Gas lift" means any method of lifting liquid to the surface by injecting gas into a well from which oil production is obtained.

22."Gas-oil ratio" means the ratio of the gas produced in cubic feet to a barrel of oil concurrently produced during any stated period.

23."Gas-oil ratio adjustment" means the reduction in allowable of a high gas-oil ratio proration unit to conform with the production permitted by the limiting gas-oil ratio for the particular pool during a particular proration period.

24."Gas transportation facility" means a pipeline in operation serving one or more gas wells for the transportation of natural gas, or some other device or equipment in like operation whereby natural gas produced from gas wells connected therewith can be transported.

25."Gas well" means a well producing gas or natural gas from a common source of gas supply as determined by the commission.

26."High gas-oil ratio proration unit" means a proration unit with a producing oil well with a gas-oil ratio in excess of the limiting gas-oil ratio for the pool.

27."Inactive pipeline" means any underground gathering pipeline system or portion thereof that has not transported fluid for more than one year.

28."Injection or input well" means any well used for the injection of air, gas, water, or other fluids into any underground stratum.

29."Injection pipeline" means a pipe or conduit of pipes used for the transportation of fluids, typically via an injection pump, from a storage tank or tank battery directly to an injection well.

30."Limiting gas-oil ratio" means the gas-oil ratio assigned by the commission to a particular oil pool to limit the volumes of casinghead gas which may be produced from the various oil-producing units within that particular pool.

31."Log or well log" means a systematic, detailed, and accurate record of one or more properties as a function of depth in an open or cased well bore. The term includes geophysical, petrophysical, image, or engineered or composite logs, or other well bore measurements acquired while drilling or by wireline operations recorded in paper or digital format.

32."Multiple completion" means the completion of any well so as to permit the production from more than one common source of supply.

33."Natural gas or gas" means and includes all natural gas and all other fluid hydrocarbons not defined as oil in this section.

34."Occupied dwelling" or "permanently occupied dwelling" means a residence which is lived in by a person at least six months throughout a calendar year.

35."Official gas-oil ratio test" means the periodic gas-oil ratio test made by order of the commission and by such method and means and in such manner as prescribed by the

36."Offset" means a well drilled on a forty-acre [16.19-hectare] tract cornering or contiguous to a forty-acre [16.19-hectare] tract having an existing oil well, or a well drilled on a one hundred sixty-acre [64.75-hectare] tract cornering or contiguous to a one hundred sixty-acre [64.75-hectare] tract having an existing gas well; provided, however, that for wells subject to a fieldwide spacing order, "offset" means any wells located on spacing units cornering or contiguous to the spacing unit or well that is the subject of an inquiry or a hearing.

37."Oil well" means any well capable of producing oil or oil and casinghead gas from a common source of supply as determined by the commission.

38."Operator" is the principal on the bond covering a well and such person shall be responsible for drilling, completion, and operation of the well, including plugging and reclamation of the well site.

39."Overage or overproduction" means the amount of oil or the amount of natural gas produced during a proration period in excess of the amount authorized on the proration schedule.

40."Potential" means the properly determined capacity of a well to produce oil, or gas, or both, under conditions prescribed by the commission.

41."Pressure maintenance" means the injection of gas or other fluid into a reservoir, either to increase or maintain the existing pressure in such reservoir or to retard the natural decline in the reservoir pressure.

42."Proration day" consists of twenty-four consecutive hours that begin at seven a.m. and end at seven a.m. on the following day.

43."Proration month" means the calendar month that begins at seven a.m. on the first day of such month and end at seven a.m. on the first day of the next succeeding month.

44."Proration schedule" means the periodic order of the commission authorizing the production, purchase, and transportation of oil or of natural gas from the various units of oil or of natural gas proration in allocated pools.

45."Proration unit for gas" consists of the geographical area prescribed by special pool rules issued by the commission.

46."Recomplete" means the subsequent completion of a well in a different pool.

47."Reservoir" means pool or common source of supply.

48."Saltwater handling facility" means and includes any container and site used for the handling, storage, disposal of substances obtained, or used, in connection with oil and gas exploration, development, and production and can be a stand-alone site or an appurtenance to a well or treating plant.

49."Shut-in pressure" means the pressure noted at the wellhead when the well is completely shut in, not to be confused with bottom hole pressure.

50."Spacing unit" is the area in each pool which is assigned to a well for drilling, producing, and proration purposes in accordance with the commission's rules or orders.

51."Stratigraphic test well" means any well or hole, except a seismograph shot hole, drilled for the

purpose of gathering information with no intent to produce oil or gas from or inject into such well.

52."Subsurface observation well" means a well used to observe subsurface phenomena, including the presence of carbon dioxide, pressure fluctuations, fluid levels and flow, temperature, and in situ water chemistry.

53."Tank bottoms" means the accumulation of hydrocarbon material and other substances which settle naturally below crude oil in tanks and receptacles that are used in handling and storing of crude oil, and which accumulation contains basic sediment and water in an amount rendering it unsalable to an ordinary crude oil purchaser; provided, that with respect to lease production and for lease storage tanks, a tank bottom must be limited to that volume of the tank in which it is contained that lies below the bottom of the pipeline outlet thereto.

54."Treating plant" means any plant permanently constructed or portable used for the purpose of wholly or partially reclaiming, treating, processing, or recycling tank bottoms, waste oils, drilling mud, waste from drilling operations, produced water, and other wastes related to crude oil and natural gas exploration and production. The term does not include saltwater handling and disposal operations that typically recover skim oil and solids from their operations, treating mud or cuttings at a well site during drilling operations, treating flowback water during completion operations at a well site, or treating tank bottoms at the well site or facility where they originated.

September 1, 2000; July 1, 2002; January 1, 2008; April 1, 2014; October 1, 2016; April 1, 2018; April 1,

History

• History: Amended effective January 1, 1983; May 1, 1992; July 1, 1996; December 1, 1996;

N.D. Admin. Code 43-02-03-02 Scope of chapter

This chapter contains general rules of statewide application which have been adopted by the industrial commission to conserve the natural resources of North Dakota, to prevent waste, and to provide for operation in a manner as to protect correlative rights of all owners of crude oil and natural gas. Special rules, pool rules, field rules, and regulations and orders have been and will be issued when required and shall prevail as against general rules, regulations, and orders if in conflict therewith.

However, wherever this chapter does not conflict with special rules heretofore or hereafter adopted, this

chapter will apply in each case. The commission may grant exceptions to this chapter, after due notice and hearing, when such exceptions will result in the prevention of waste and operate in a manner to protect correlative rights.

History

• History: Amended effective May 1, 1992.

N.D. Admin. Code 43-02-03-03 Promulgation of rules, regulations, or orders

N.D. Admin. Code 43-02-03-04 Emergency rule, regulation, or order

N.D. Admin. Code 43-02-03-05 Enforcement of laws, rules, and regulations dealing with conservation of oil and gas

The commission, its agents, representatives, and employees are charged with the duty and obligation of enforcing all rules and statutes of North Dakota relating to the conservation of oil and gas.

However, it shall be the responsibility of all the owners, operators, and contractors to obtain information pertaining to the regulation of oil and gas before operations have begun.

History

• History: Amended effective May 1, 2004; April 1, 2012; April 1, 2018.

N.D. Admin. Code 43-02-03-06 Waste prohibited

All operators, contractors, drillers, carriers, gas distributors, service companies, pipe pulling and salvaging contractors, or other persons shall at all times conduct their operations in the drilling, equipping, operating, producing, plugging, and site reclamation of oil and gas wells in a manner that will prevent waste.

History

• History: Amended effective January 1, 1983; May 1, 1992.
• General Authority: NDCC 38-08-03
• Law Implemented: NDCC 38-08-03

N.D. Admin. Code 43-02-03-07 United States government leases

The commission recognizes that all persons drilling and producing on United States government land shall comply with the United States government regulations. Such persons shall also comply with all applicable state rules and regulations. Copies of the sundry notices, reports on wells, and well data required by this chapter of the wells on United States government land shall be furnished to the commission at no expense to the commission.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1994; April 1, 2022.

N.D. Admin. Code 43-02-03-08 Classifying and defining pools

N.D. Admin. Code 43-02-03-09 Forms

Forms required by the commission will be furnished upon request. The commission will provide electronic submission for most requests and reports.

History

• History: Amended effective April 1, 2022.

N.D. Admin. Code 43-02-03-10 Authority to cooperate with other agencies

The commission may from time to time enter agreements with state and federal government agencies, tribal governments, industry committees, and individuals with respect to special projects, services, and studies relating to conservation of oil and gas.

History

• History: Amended effective April 1, 2020.

N.D. Admin. Code 43-02-03-11 Organization reports

Every person acting as principal or agent for another or independently engaged in the drilling of oil or gas wells, or in the production, storage, transportation, refining, reclaiming, treating, marketing, or processing of crude oil or natural gas, engaged in the disposal of produced water, engaged in treating plant operations, or engaged in pipeline operations in North Dakota shall immediately file with the director the name under which such business is being conducted or operated; and name and post-office address of such person, the business or businesses in which the person is engaged; the plan of organization, and in case of a corporation, the law under which it is chartered; and the names and post-office addresses of any person acting as trustee, together with the names and post-office addresses of any officials thereof on an organization report (form 2). In each case where such business is conducted under an assumed name, such organization report shall show the names and post-office addresses of all owners in addition to the other information required. A new organization report shall be filed when and if there is a change in any of the information contained in the original report.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; September 1, 2000; April 1, 2014; October 1, 2016.

N.D. Admin. Code 43-02-03-12 Reservoir surveys

By special order of the commission, periodic surveys may be made of the reservoirs in this state containing oil and gas. These surveys will be thorough and complete and shall be made using methods approved by the director. The condition of the reservoirs containing oil and gas and the practices and methods employed by the operators shall be investigated. The produced volume and source of crude oil and natural gas, the reservoir pressure of the reservoir as an average, the areas of regional or differential pressure, stabilized gas-oil ratios, and the producing characteristics of the field as a whole and the individual wells within the field shall be specifically included.

All operators of oil wells are required to permit and assist the agents of the commission in making any and all special tests that may be required by the commission on any or all wells.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; September 1, 2000.

N.D. Admin. Code 43-02-03-13 Record of wells

The director shall maintain a record of official well names, to be known as the well-name register, in which shall be entered: (1) the name and location of each well; (2) the well file number; (3) the name of the operator, or the operator's agent; and (4) any subsequent name or names assigned to the well and approved by the director.

The last name assigned to a well in the well-name register shall be the official name of the well, and the one by which it shall be known and referred to.

The director may, at the director's discretion, grant or refuse an application to change the official name. The application shall be accompanied by a fee of twenty-five dollars, which fee is established to cover the expense of recording the change. If the application is refused, the fee shall be refunded.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992.

N.D. Admin. Code 43-02-03-14 Access to sites and records

The commission, director, and their representatives shall have access to all records wherever located. All owners, operators, drilling contractors, drillers, service companies, or other persons engaged in drilling, completing, producing, operation, or servicing oil and gas wells, pipelines, injection wells, stratigraphic test wells, subsurface observation wells, or treating plants shall permit the commission, director, and their representatives to come upon any lease, property, pipeline right-of-way, well, or drilling rig operated or controlled by them, complying with state safety rules, and to inspect the records and operation, and to have access at all times to any and all records. If requested, copies of such records must be filed with the commission. The confidentiality of any data submitted which is confidential pursuant to subdivision f of subsection 1 of North Dakota Century Code section 38-08-04 and section 43-02-03-31 must be maintained.

October 1, 2016; April 1, 2024. 43-02-03-14.1. Verification of certified welders.

Repealed effective July 1, 1996. 43-02-03-14.2. Oil and gas metering systems.

1.This section is applicable to all allocation and custody transfer metering stations measuring production from oil and gas wells within the state of North Dakota, including private, state, and federal wells. If these rules differ from federal requirements on measurement of production from federal oil and gas wells, the federal rules take precedence.

2.As used in this section:

a."Allocation meter" means a meter used by the producer to determine the volume from an individual well before it is commingled with production from one or more other wells prior to the custody transfer point.

b."Calibration test" means the process or procedure of adjusting an instrument, such as a gas meter, so its indication or registration is in satisfactorily close agreement with a reference standard.

c."Custody transfer meter" means a meter used to transfer oil or gas from the producer to transporter or purchaser.

d."Gas gathering meter" means a meter used in the custody transfer of gas into a gathering system.

e."Meter factor" means a number obtained by dividing the net volume of fluid (liquid or gaseous) passed through the meter during proving by the net volume registered by the meter.

f."Metering proving" means the procedure required to determine the relationship between the true volume of a fluid (liquid or gaseous) measured by a meter and the volume indicated by the meter.

3.The owner of meter proving equipment shall file with the director an inventory of all conventional pipe provers or master-meter provers used to test the accuracy of oil meters.

Inventories must be updated on an annual basis, and filed with the director on or before the first day of each year, or they may be updated as frequently as monthly, at the discretion of the operator. Inventories must include the following:

a.Meter information:

(1)Prover:

(a)Type.

(b)Serial number.

(c)Prover volume.

(d)Most recent water draw certificate.

(2)Master meter:

(a)Make and model.

(b)Size.

(c)Serial number.

(d)Master meter factor.

(e)Most recent meter proving certificate.

(3)An inventory of all meters used for custody transfer and allocation of production from oil and gas wells, or both must be filed with the director upon request.

4.The director must be notified of all custody transfer meters placed in service. The owner of the custody transfer equipment shall notify the director of the date a meter is placed in service, the make and model of the meter, and the meter or station number. The director must also be notified of all metering installations removed from service. The notice must include the date the meter is removed from service, the serial number, and the meter or station number. The required notices must be filed with the director within thirty days of the installation or removal of a meter.

All allocation meters must be approved prior to installation and use. The application for approval must be on a facility sundry notice and shall include the make and model number of the meter, the meter or station number, the serial number, the well name, its location, and the date the meter will be placed in service.

Meter installations for measuring production from oil or gas wells, or both, must be constructed to American petroleum institute or American gas association standards or to meter manufacturer's recommended installation. Meter installations constructed in accordance with American petroleum institute or American gas association standards in effect at the time of installation shall not automatically be required to retrofit if standards are revised. The director will review any revised standards, and when deemed necessary will amend the requirements accordingly.

5.All persons engaged in meter proving or testing of oil and gas meters must be registered with the director. Those persons involved in oil meter testing, by flowing fluid through the meter into a test tank and then gauging the tank, are exempted from the registration process. However, such persons must notify the director prior to commencement of the test to allow a representative of the director to witness the testing process. A report of the results of such test shall be filed with the director within thirty days after the test is completed. Registration must

a.Name and address of company.

b.Name and address of measurement personnel.

c.Qualifications, listing experience or specific training.

Any meter tests performed by a person not registered with the director will not be accepted as a valid test.

6.Oil and gas metering equipment must be proved or tested to American petroleum institute or American gas association standards or to the meter manufacturer's recommended procedure to establish a meter factor or to ensure measurement accuracy. The owner of a custody transfer meter or allocation meter shall notify the director at least ten days prior to the testing of any meter.

a.Oil allocation meter factors must be maintained within two percent of original meter factor. If the factor change between provings or tests is greater than two percent, meter use must be discontinued until successfully reproven after being repaired or replaced.

b.Oil custody transfer meter factors must be maintained within one-quarter of one percent of the previous meter factor. If the factor change between provings or tests is greater than one-quarter of one percent, meter use must be discontinued until successfully reproven after being repaired or replaced.

c.Copies of all oil allocation meter test procedures must be filed with and reviewed by the director to ensure measurement accuracy.

d.All gas meters must be tested with a minimum of a three-point test for static and differential pressure elements and a two-point test for temperature elements. The test reports must include an as-found and as-left test and a detailed report of changes.

e.Test reports must include the following:

(1)Company name of test contractor.

(2)Pipeline company name.

(3)Meter owner name.

(4)Producer name.

(5)Well or central tank battery (CTB) name.

(6)Well file number or CTB number.

(7)Test personnel's name.

(8)Station or meter number.

f.Unless required more often by the director, minimum frequency of meter proving or calibration tests are as follows:

(1)Oil meters used for custody transfer must be proved monthly for all measured volumes which exceed two thousand barrels per month. For volumes two thousand barrels or less per month, meters must be proved at each two thousand barrel interval or more frequently at the discretion of the operator.

(2)Quarterly for oil meters used for allocation of production in a diverse ownership central production facility. Semiannually for oil meters used for allocation of production in a common ownership central production facility.

(3)Semiannually for gas meters used for allocation of production in a diverse ownership central production facility. Annually for gas meters used for allocation of production in a common ownership central production facility.

(4)Semiannually for gas meters in gas gathering systems.

(5)For meters measuring more than one hundred thousand cubic feet [2831.68 cubic meters] per day on a monthly basis, orifice plates must be inspected semiannually, and meter tubes must be inspected at least every five years to ensure continued conformance with the American gas association meter tube specifications.

(6)For meters measuring one hundred thousand cubic feet [2831.68 cubic meters] per day or less on a monthly basis, orifice plates must be inspected annually.

g.Accuracy of all equipment used to test oil or gas meters must be traceable to the standards of the national institute of standards and technology. The equipment must be certified as accurate either by the manufacturer or an independent testing facility. The certificates of accuracy for all equipment used to test gas meters must be made available upon request. The owner of a conventional pipe prover or master meter prover shall notify the director at least ten days prior to the testing of any prover. Certification of the equipment must be updated as follows:

(1)Annually for all equipment used to test the pressure and differential pressure elements.

(2)Annually for all equipment used to determine temperature.

(3)Biennially for all conventional pipe provers.

(4)Annually for all master meters.

(5)Five years for equipment used in orifice tube inspection.

h.All meter test reports, including failed meter test reports, must be filed within thirty days of completion of proving or calibration tests unless otherwise approved, and must be submitted by email in a portable document format (.pdf) or another format approved by the director. Test reports must be filed on, but not limited to, all meters used for allocation measurement of oil or gas, all meters used in custody transfer, conventional pipe provers, and master meter provers.

7.Variances from all or part of this section may be granted by the director provided the variance does not affect measurement accuracy. Requests for variances may be granted verbally by the director but must be filed by the meter owner on a facility sundry notice.

A register of variances requested and approved must be maintained by the director.

April 1, 2018; April 1, 2020; April 1, 2022; April 1, 2024; April 1, 2026.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; May 1, 1994; April 1, 2014;
• History: Effective May 1, 1994; amended effective July 1, 1996; September 1, 2000; July 1, 2002;
• Law Implemented: NDCC 38-08-04, 38-08-20

N.D. Admin. Code 43-02-03-15 Bond and transfer of wells

1.Bond requirements. Prior to commencing construction of a site or appurtenance or road access thereto, any person who proposes to drill a well for oil, gas, injection, or source well for use in enhanced recovery operations, shall submit to the director and obtain the approval of the director, a surety bond or cash bond. An alternative form of security may be approved by the commission after notice and hearing, as provided by law. The operator of such well shall be the principal on the bond covering the well. Each surety bond shall be executed by a responsible surety company authorized to transact business in North Dakota.

2.Bond amounts and limitations. The bond shall be in the amount of fifty thousand dollars when applicable to one well only. Wells drilled to a total depth of less than two thousand feet [609.6 meters] may be bonded in a lesser amount if approved by the director. When the principal on the bond is drilling or operating a number of wells within the state or proposes to do so, the principal may submit a bond conditioned as provided by law. Wells utilized for commercial injection operations must be bonded in the amount of one hundred thousand dollars. A blanket bond covering more than one well shall be in the amount of one hundred thousand dollars, provided the bond shall be limited to no more than six of the following in aggregate:

a.A well that is a dry hole and is not properly plugged;

b.A well that is plugged and the site is not properly reclaimed;

c.A well that is abandoned pursuant to subsection 1 of North Dakota Century Code section 38-08-04 or section 43-02-03-55 and is not properly plugged and the site is not properly reclaimed; and

d.A well that is temporarily abandoned under section 43-02-03-55 for more than seven years.

If this aggregate of wells is reached, all well permits, for which drilling has not commenced, held by the principal of such bond are suspended. No rights may be exercised under the permits until the aggregate of wells drops below the required limit, or the operator files the appropriate bond to cover the permits, at which time the rights given by the drilling permits are reinstated. A well with an approved temporary abandoned status for no more than seven years shall have the same status as an oil, gas, or injection well. The commission may, after notice and hearing, require higher bond amounts than those referred to in this section. Such additional amounts for bonds must be related to the economic value of the well or wells and the expected cost of plugging and well site reclamation, as determined by the director. The director may refuse to accept a bond or to add wells to a blanket bond if the operator or surety company has failed in the past to comply with statutes, rules, or orders relating to the operation of wells; if a civil or administrative action brought by the commission is pending against the operator or surety company; or for other good cause.

3.Unit bond requirements. Prior to commencing unit operations, the operator of any area under unitized management shall submit to the director and obtain the approval of the director, a surety bond or cash bond. An alternative form of security may be approved by the commission after notice and hearing, as provided by law. The operator of the unit shall be the principal on the bond covering the unit. The amount of the bond shall be specified by the commission in the order approving the plan of unitization. Each surety bond shall be executed by a responsible surety company authorized to transact business in North Dakota.

Prior to transfer of a unit to a new operator, the commission, after notice and hearing, may revise the bond amount for a unit, or in the case when the unit was not previously bonded, the commission may require a bond and set a bond amount for the unit.

4.Bond terms. Bonds shall be conditioned upon full compliance with North Dakota Century Code chapter 38-08, and all administrative rules and orders of the commission. It shall be a plugging bond, as well as a drilling bond, and is to endure up to and including approved plugging of all oil, gas, and injection wells as well as dry holes. Approved plugging shall also include practical reclamation of the well site and appurtenances thereto. If the principal does not satisfy the bond's conditions, then the surety shall satisfy the conditions or forfeit to the commission the face value of the bond.

5.Transfer of wells under bond. Transfer of property does not release the bond. In case of transfer of property or other interest in the well and the principal desires to be released from the bond covering the well, such as producers, not ready for plugging, the principal must proceed as follows:

a.The principal must notify the director, in writing, of all proposed transfers of wells at least thirty days before the closing date of the transfer. The director may, for good cause, waive this requirement.

(1)The principal shall submit a schematic drawing identifying all lines owned by the principal which leave the constructed pad or facility and shall provide any details the director deems necessary.

(2)The principal shall submit to the director a form 15 reciting that a certain well, or wells, describing each well by quarter-quarter, section, township, and range, is to be transferred to a certain transferee, naming such transferee, for the purpose of ownership or operation. The date of assignment or transfer must be stated and the form signed by a party duly authorized to sign on behalf of the principal.

(3)On said transfer form the transferee shall recite the following: "The transferee has read the foregoing statement and does accept such transfer and does accept the responsibility of such well under the transferee's one-well bond or, as the case may be, does accept the responsibility of such wells under the transferee's blanket bond, said bond being tendered to or on file with the commission." Such acceptance must likewise be signed by a party authorized to sign on behalf of the transferee and the transferee's surety.

b.When the director has passed upon the transfer and acceptance and accepted it under the transferee's bond, the transferor shall be released from the responsibility of plugging the well and site reclamation. If such wells include all the wells within the responsibility of the transferor's bond, such bond will be released by the director upon written request.

Such request must be signed by an officer of the transferor or a person authorized to sign for the transferor. The director may refuse to transfer any well from a bond if any well on the bond is in violation of a statute, rule, or order. No abandoned well may be transferred from a bond unless the transferee has obtained a single well bond in an amount equal to the cost of plugging the well and reclaiming the well site.

c.The transferee (new operator) of any well shall be responsible for the plugging and site reclamation of any such well and appurtenance thereto where the reclamation and restoration of land and water resources impacted by oil and gas development is in an inadequate reclamation status. For that purpose the transferee shall submit a new bond or, in the case of a surety bond, produce the written consent of the surety of the original or prior bond that the latter's responsibility shall continue and attach to such well. The original or prior bond shall not be released as to the plugging and reclamation responsibility of any such transferor until the transferee shall submit to the director an acceptable bond to cover such well. All liability on bonds shall continue until the plugging and site reclamation of such wells is completed and approved.

6.Treating plant bond. Prior to commencing site or road access construction, any person proposing to operate a treating plant must submit to the director and obtain the approval of the director, a surety bond or cash bond. An alternative form of security may be approved by the commission after notice and hearing, as provided by law. The person responsible for the operation of the plant shall be the principal on the bond. Each surety bond shall be executed by a responsible surety company authorized to transact business in North Dakota. The amount of the bond must be as prescribed in section 43-02-03-51.3. It is to remain in force until the operations cease, all equipment is removed from the site, and the site and appurtenances thereto are reclaimed, or liability of the bond is transferred to another bond that provides the same degree of security. If the principal does not satisfy the bond's conditions, then the surety shall satisfy the conditions or forfeit to the commission the face value of the bond.

7.Saltwater handling facility bond. Prior to commencing site or road access construction, any person proposing to operate a saltwater handling facility that is not already bonded as an appurtenance shall submit to the director and obtain the approval of the director, a surety bond or cash bond. An alternative form of security may be approved by the commission after notice and hearing, as provided by law. The person responsible for the operation of the saltwater handling facility must be the principal on the bond. Each surety bond must be executed by a responsible surety company authorized to transact business in North Dakota.

The amount of the bond must be as prescribed in section 43-02-03-53.3. It is to remain in force until the operations cease, all equipment is removed from the site, and the site and appurtenances thereto are reclaimed, or liability of the bond is transferred to another bond that provides the same degree of security. If the principal does not satisfy the bond's conditions, the surety shall satisfy the conditions or forfeit to the commission the face value of the bond.

Transfer of property does not release the bond. The director may refuse to transfer any saltwater handling facility from a bond if the saltwater handling facility is in violation of a statute, rule, or order.

8.Crude oil and produced water underground gathering pipeline bond. The bonding requirements for crude oil and produced water underground gathering pipelines are not to be construed to be required on flow lines, injection pipelines, pipelines operated by an enhanced recovery unit for enhanced recovery unit operations, or on piping utilized to connect wells, tanks, treaters, flares, or other equipment on the production facility.

a.Any owner of an underground gathering pipeline transferring crude oil or produced water, after April 19, 2015, shall submit to the director and obtain the approval of the director, a surety bond or cash bond prior to July 1, 2017. Any owner of a proposed underground gathering pipeline to transfer crude oil or produced water shall submit to the director and obtain the approval of the director, a surety bond or cash bond prior to placing into service. An alternative form of security may be approved by the commission after notice and hearing, as provided by law. The person responsible for the operation of the crude oil or produced water underground gathering pipeline must be the principal on the bond.

Each surety bond must be executed by a responsible surety company authorized to transact business in North Dakota. The bond must be in the amount of fifty thousand dollars when applicable to one crude oil or produced water underground gathering pipeline system only. Such underground gathering pipelines that are less than one mile [1609.34 meters] in length may be bonded in a lesser amount if approved by the director.

When the principal on the bond is operating multiple gathering pipeline systems within the state or proposes to do so, the principal may submit a blanket bond conditioned as provided by law. A blanket bond covering one or more underground gathering pipeline systems must be in the amount of one hundred thousand dollars. The owner shall file with the director, as prescribed by the director, a geographical information system layer utilizing North American datum 83 geographic coordinate system and in an environmental systems research institute shape file format showing the location of all associated above ground equipment and the pipeline centerline from the point of origin to the termination point of all underground gathering pipelines on the bond. Each layer must include at least the following information:

(1)The name of the pipeline gathering system and other separately named portions thereof;

(2)The type of fluid transported;

(3)The pipeline composition;

(4)Burial depth; and (5)Approximate in-service date.

b.The blanket bond covering more than one underground gathering pipeline system is limited to no more than six of the following instances of noncompliance in aggregate:

(1)Any portion of an underground gathering pipeline system that has been removed from service for more than one year and is not properly abandoned pursuant to

section 43-02-03-29.1; and (2)An underground gathering pipeline right-of-way, including associated above ground equipment, which has not been properly reclaimed pursuant to section If this aggregate of underground gathering pipeline systems is reached, the director may refuse to accept additional pipeline systems on the bond until the aggregate is brought back into compliance. The commission, after notice and hearing, may require higher bond amounts than those referred to in this section. Such additional amounts for bonds must be related to the economic value of the underground gathering pipeline system and the expected cost of pipeline abandonment and right-of-way reclamation, as determined by the director. The director may refuse to accept a bond or to add underground gathering pipeline systems to a blanket bond if the owner or surety company has failed in the past to comply with statutes, rules, or orders relating to the operation of underground gathering pipelines; if a civil or administrative action brought by the commission is pending against the owner or surety company; if an underground gathering pipeline system has exhibited multiple failures; or for other good cause.

c.The underground gathering pipeline bond is to remain in force until the pipeline has been abandoned, as provided in section 43-02-03-29.1, and the right-of-way, including all associated above ground equipment, has been reclaimed as provided in section 43-02-03-29.1, or liability of the bond is transferred to another bond that provides the same degree of security. If the principal does not satisfy the bond's conditions, the surety shall satisfy the conditions or forfeit to the commission the face value of the bond.

d.Transfer of underground gathering pipelines under bond. Transfer of property does not release the bond. In case of transfer of property or other interest in the underground gathering pipeline and the principal desires to be released from the bond covering the underground gathering pipeline, the principal must proceed as follows:

(1)The principal shall notify the director, in writing, of all proposed transfers of underground gathering pipelines at least thirty days before the closing date of the transfer. The director, for good cause, may waive this requirement.

Notice of underground gathering pipeline transfer. The principal shall submit, as provided by the director, a geographical information system layer utilizing North American datum 83 geographic coordinate system and in an environmental systems research institute shape file format showing the location of all associated above ground equipment and the pipeline centerline from the point of origin to the termination point of all underground gathering pipelines to be transferred to a certain transferee, naming such transferee, for the purpose of ownership or operation. The date of assignment or transfer must be stated and the form 15pl signed by a party duly authorized to sign on behalf of the principal.

The notice of underground gathering pipeline transfer must recite the following: "The transferee has read the foregoing statement and does accept such transfer and does accept the responsibility of such underground gathering pipelines under the transferee's pipeline bond or, as the case may be, does accept the responsibility of such underground gathering pipelines under the transferee's pipeline systems blanket bond, said bond being tendered to or on file with the commission." Such acceptance must likewise be signed by a party authorized to sign on behalf of the transferee and the transferee's surety.

(2)When the director has passed upon the transfer and acceptance and accepted it under the transferee's bond, the transferor must be released from the responsibility of abandoning the underground gathering pipelines and right-of-way reclamation. If such underground gathering pipelines include all underground gathering pipeline systems within the responsibility of the transferor's bond, such bond will be released by the director upon written request. Such request must be signed by an officer of the transferor or a person authorized to sign for the transferor. The director may refuse to transfer any underground gathering pipeline from a bond if the underground gathering pipeline is in violation of a statute, rule, or order.

(3)The transferee (new owner) of any underground gathering pipeline is responsible for the abandonment and right-of-way reclamation of any such underground gathering pipeline. For that purpose the transferee shall submit a new bond or, in the case of a surety bond, produce the written consent of the surety of the original or prior bond that the latter's responsibility shall continue and attach to such underground gathering pipeline. The original or prior bond may not be released as to the abandonment and right-of-way reclamation responsibility of any such transferor until the transferee submits to the director an acceptable bond to cover such underground gathering pipeline. All liability on bonds continues until the abandonment and right-of-way reclamation of such underground gathering pipeline is completed and approved by the director.

9.Geological storage facility bond requirements. Before commencing injection operations, the operator of any storage facility shall submit to the director and obtain the approval of the director, a surety bond or cash bond in the amount specified by the commission in the order approving the storage facility. An alternative form of security may be approved by the commission after notice and hearing, as provided by law. The operator of the storage facility shall be the principal on the bond covering the storage facility. Each surety bond must be executed by a responsible surety company authorized to transact business in North Dakota.

10.Enhanced oil recovery potential well bond. Before the director may approve a nonunit well for enhanced oil recovery potential status, the operator shall submit to the director and obtain the approval of the director for, a blanket surety bond or cash bond in the amount of one hundred thousand dollars, provided the bond shall be limited to no more than six wells that have been inactive for more than twelve years. Wells within an approved enhanced recovery unit approved for enhanced oil recovery potential status may remain on the unit bond at the discretion of the director. An alternative form of security may be approved by the commission after notice and hearing, as provided by law. The operator of such well shall be the principal on the bond covering the well. Each surety bond must be executed by a responsible surety company authorized to transact business in North Dakota. Each such bond may be subject to an annual review to determine if the bond amount is sufficient and the commission may, after notice and hearing, require a higher bond amount. Such additional amounts for bonds must be related to the economic value of the well or wells and the expected cost of plugging and well site reclamation, as determined by the director. The director may refuse to accept a bond or to add wells to an enhanced oil recovery potential blanket bond if the operator or surety company has failed in the past to comply with statutes, rules, or orders relating to the operation of wells; if a civil or administrative action brought by the commission is pending against the operator or surety company; or for other good cause.

11.Bond termination. The director shall, in writing, advise the principal and any sureties on any bond as to whether the plugging and reclamation is approved. If approved, liability under such bond may be formally terminated upon receipt of a written request by the principal. The request must be signed by an officer of the principal or a person authorized to sign for the principal.

12.Director's authority. The director is vested with the power to act for the commission as to all matters within this section, except requests for alternative forms of security, which may only be approved by the commission.

May 1, 1994; July 1, 1996; December 1, 1996; September 1, 2000; July 1, 2002; May 1, 2004;

January 1, 2006; April 1, 2012; April 1, 2014; October 1, 2016; April 1, 2018; April 1, 2020; April 1, 2022;

April 1, 2024.

History

• History: Amended effective April 30, 1981; March 1, 1982; January 1, 1983; May 1, 1990; May 1, 1992;

N.D. Admin. Code 43-02-03-16 Application for permit to drill and recomplete

1.Before any person may begin any well-site preparation for the drilling of any well other than surveying and staking, such person shall obtain approval from the director. An application for permit to drill must be filed with the director, together with a permit fee of one hundred dollars.

Site construction, or appurtenance or road access thereto, may not commence until such application is approved and a permit to drill is issued by the director. Verbal approval may be given for site preparation by the director in extenuating circumstances to include contractual obligations, an expiring lease, or an expiring right-of-way. The application must be accompanied by the bond pursuant to section 43-02-03-15 or the applicant must have previously filed such bond with the director, otherwise the application is incomplete. An incomplete application received by the director has no standing and is not deemed filed until it is completed.

2.The application for permit to drill must be accompanied by an accurate plat certified by a registered surveyor showing the location of the proposed well with reference to true north and the nearest lines of a governmental section, the latitude and longitude of the proposed well location to the nearest tenth of a second, the ground elevation, and the proposed road access to the nearest existing public road. Information in the application must include the proposed depth to which the well will be drilled; estimated depth to the top of important markers; estimated depth to the top of objective horizons; the proposed mud program; the proposed casing program, including size and weight thereof; the depth at which each casing string is to be set; the proposed amount of cement to be used, including the estimated top of cement; the proposed pad layout plat, including cut and fill diagrams; and the proposed production facilities layout plat.

3.For wells permitted on new pads built after July 31, 2013, permit conditions imposed by the director may include, upon request of the owner of a permanently occupied dwelling within one thousand feet of the proposed well, requiring the location of all flares, tanks, and treaters utilized in connection with the permitted well be located at a greater distance from the occupied dwelling than the well head, if the location can be reasonably accommodated within the proposed pad location. If the facilities are proposed to be located farther from the dwelling than the well bore, the director can issue the permit without comment from the dwelling owner.

The applicant shall give any such owners written notice of the proposed facilities personally or by certified mail, return receipt requested, and addressed to their last-known address listed with the county property tax department. The director must receive written comments from such owner within five business days of the owner receiving said notice. An application for permit must include an affidavit from the applicant identifying each owner's name and address, and the date written notice was given to each owner. The owner's notice must include:

a.A copy of North Dakota Century Code section 38-08-05.

b.The name, telephone number, and if available the electronic mail address of the applicant's local representative.

c.A sketch of the area indicating the location of the owner's dwelling; the proposed well; and location of the proposed flare, tanks, and treaters.

d.A statement indicating that any such owner objecting to the location of the flare, tanks, or treaters, shall notify the director within five business days of receiving the notice.

4.Prior to the commencement of recompletion operations or drilling horizontally in the existing pool, an application for permit must be approved by the director. Such application must be filed to reenter a well by drilling horizontally, deepening, or plugging back to any source of supply other than the producing horizon in an existing well. Such notice must include the name and file number and exact location of the well, the approximate date operations will begin, the proposed procedure, the estimated completed total depth, the anticipated hydrogen sulfide content in produced gas from the proposed source of supply, the weight and grade of all casing currently installed in the well unless waived by the director, the casing program to be followed, and the original total depth with a permit fee of fifty dollars. The director may deny any application if it is determined, in accordance with the latest version of ANSI/NACE MR0175/ISO 15156, that the casing currently installed in the well would be subject to sulfide stress cracking.

5.The applicant shall provide all information, in addition to that specifically required by this

section, if requested by the director. The director may impose such terms and conditions on the permits issued under this section as the director deems necessary.

6.The director shall deny an application for a permit under this section if the proposal would cause, or tend to cause, waste or violate correlative rights. The director of oil and gas shall state in writing to the applicant the reason for the denial of the permit. The applicant may appeal the decision of the director to the commission.

7.A permit to drill automatically expires one year after the date it was issued, unless the well is drilling or has been drilled below surface casing. A permit to recomplete or to drill horizontally automatically expires one year after the date it was issued, unless such project has commenced. The director may extend a permit to drill and a permit to recomplete or drill horizontally for up to one year upon request.

The principal on the bond covering a well, treating plant, or facility is the operator. The operator is responsible for compliance with all applicable laws. A dispute over designation of the operator may be addressed by the commission. In doing so, the factors the commission may consider include those set forth in subsection 1 of section 43-02-03-16.2.

1.After notice and hearing, the commission may revoke a drilling, recompletion, or reentry permit or limit its duration. The commission may act upon its own motion or upon the application of an owner in the spacing or drilling unit. In deciding whether to revoke or limit a permit, the factors that the commission may consider include:

a.The technical ability of the permitholder and other owners to drill and complete the well.

b.The experience of the permitholder and other owners in drilling and completing similar wells.

c.The number of wells in the area operated by the permitholder and other owners.

d.Whether drainage of the spacing or drilling unit has occurred or is likely to occur in the immediate future and whether the permitholder has committed to drill a well in a timely fashion.

e.Contractual obligations such as an expiring lease.

f.The amount of ownership the permitholder and other owners hold in the spacing or drilling unit. If the permitholder is the majority owner in the unit or if its interest when combined with that of its supporters is a majority of the ownership, it is presumed that the permitholder should retain the permit. This presumption, even if not rebutted, does not prohibit the commission from limiting the duration of the permit. However, if the amount of the interest owned by the owner seeking revocation or limitation and its supporters are a majority of the ownership, the commission will presume that the permit should be revoked.

2.The commission may suspend a permit that is the subject of a revocation or limitation proceeding, although a permit will not be suspended after operations have commenced.

3.If the commission revokes a permit upon the application of an owner and issues a permit to that owner or to another owner who supported revocation, the commission may limit the duration of such permit. The commission may also, if the parties fail to agree, order the owner acquiring the permit to pay reasonable costs incurred by the former permitholder and the conditions under which payment is to be made. The costs for which reimbursement may be ordered may include those involving survey of the well site, title search of surface and mineral title, and preparation of an opinion of mineral ownership.

4.If the commission declines to revoke a permit or limit the time within which it must be exercised, it may include a term in its order restricting the ability of the permitholder to renew the permit or to acquire another permit within the same spacing or drilling unit.

The following govern the recovery of the risk penalty pursuant to subsection 3 of North Dakota Century Code section 38-08-08 and subsection 3 of North Dakota Century Code section 38-08-09.4:

1.An owner may recover the risk penalty under the provisions of subsection 3 of North Dakota Century Code section 38-08-08, provided the owner gives, to the owner from whom the penalty is sought, a written invitation to participate in the risk and cost of drilling a well, including reentering a plugged and abandoned well, or the risk and cost of reentering an existing well to drill deeper or a horizontal lateral. If the nonparticipating owner's interest is not subject to a lease or other contract for development, an owner seeking to recover a risk penalty must also make a good-faith attempt to have the unleased owner execute a lease.

a.The invitation to participate in drilling must be in writing and contain the following:

(1)The approximate surface location of the proposed or existing well, proposed completion and total depth, objective zone, and completion location if other than a vertical well.

(2)An itemization of the estimated costs of drilling and completion.

(3)The approximate date upon which the well was or will be spudded or reentered.

(4)A written election to participate and a statement indicating the invitation or election must be accepted within thirty days of receiving it. Such election to participate must be received by the owner giving the invitation within thirty days of the participating party's receipt.

(5)Notice that the participating owners plan to impose a risk penalty and that the nonparticipating owner may object to the risk penalty by either responding in opposition to the petition for a risk penalty, or if no such petition has been filed, by filing an application or request for hearing with the commission.

(6)Drilling or spacing unit description.

b.An invitation to participate and an election to participate must be served personally, by mail requiring a signed receipt, or by overnight courier or delivery service requiring a signed receipt. Failure to accept mail requiring a signed receipt constitutes service.

c.An election to participate is only binding upon an owner electing or declining to participate if the well is spudded or reentry operations are commenced on or before ninety days after the date the owner extending the invitation to participate sets as the date upon which an election response to the invitation is to be received. It also expires if the permit to drill or reenter expires without having been exercised. If an election to participate lapses, a risk penalty can only be collected if the owner seeking it again complies with the provisions of this section.

2.An owner may recover the risk penalty under the provisions of subsection 3 of North Dakota Century Code section 38-08-09.4, provided the owner gives, to the owner from whom the penalty is sought, a written invitation to participate in the unit expense. If the nonparticipating owner's interest is not subject to a lease or other contract for development, an owner seeking to recover a risk penalty must also make a good-faith attempt to have the unleased owner execute a lease.

a.The invitation to participate in the unit expense must be in writing and contain the (1)A description of the proposed unit expense, including the location, objectives, and plan of operation.

(2)An itemization of the estimated costs.

(3)The approximate date upon which the proposal was or will be commenced.

(4)A written election to participate and a statement indicating the invitation or election must be accepted within thirty days of receiving it. Such election to participate must be received by the owner giving the invitation within thirty days of the participating party's receipt.

(5)Notice that the participating owners plan to impose a risk penalty and that the nonparticipating owner may object to the risk penalty by either responding in opposition to the petition for a risk penalty, or if no such petition has been filed, by filing an application or request for hearing with the commission.

b.An invitation to participate and an election to participate must be served personally, by mail requiring a signed receipt, or by overnight courier or delivery service requiring a signed receipt. Failure to accept mail requiring a signed receipt constitutes service.

c.An election to participate is only binding upon an owner electing or declining to participate if the unit expense is commenced within ninety days after the date the owner extending the invitation request to participate sets as the date upon which an election response to the request invitation is to be received. If an election to participate lapses, a risk penalty can only be collected if the owner seeking it again complies with the provisions of this section.

d.An invitation to participate in a unit expense covering monthly operating expenses shall be effective for all such monthly operating expenses for a period of five years if the unit expense identified in the invitation to participate is first commenced within ninety days after the date set in the invitation to participate as the date upon which an election response to the invitation to participate must be received. An election to participate in a unit expense covering monthly operating expenses is effective for five years after operations are first commenced. If an election to participate in a unit expense comprised of monthly operating expenses expires or lapses after five years, a risk penalty may only be assessed and collected if the owner seeking the penalty once again complies with this

section.

3.Upon its own motion or the request of a party, the commission may include in a pooling order requirements relating to the invitation to participate and election to participate, in which case the pooling order will control to the extent it is inconsistent with this section.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; May 1, 1994; September 1, 2000; July 1, 2002; April 1, 2010; April 1, 2012; April 1, 2014; October 1, 2016; April 1, 2020; April 1,
• General Authority: NDCC 38-08-05
• Law Implemented: NDCC 38-08-05 43-02-03-16.1. Designation and responsibilities of operator.
• History: Effective December 1, 1996; amended effective April 1, 2014; April 1, 2022. 43-02-03-16.2. Revocation and limitation of drilling permits.
• History: Effective December 1, 1996; amended effective January 1, 2006; April 1, 2020. 43-02-03-16.3. Recovery of a risk penalty.
• History: Effective December 1, 1996; amended effective May 1, 2004; January 1, 2006; January 1, 2008; April 1, 2010; April 1, 2012; April 1, 2014; April 1, 2020; April 1, 2024.
• Law Implemented: NDCC 38-08-04, 38-08-08

N.D. Admin. Code 43-02-03-17 Sign on well and facility

Every well and facility associated with the production, transportation, purchasing, storage, treating, or processing of oil, gas, and water except plugged wells shall be identified by a sign. The sign shall be of durable construction and the lettering thereon shall be kept in a legible condition. The wells on each lease or property shall be numbered in nonrepetitive sequence, unless some other system of numbering was adopted by the owner prior to the adoption of this chapter. Each sign must show the facility name or well name and number (which shall be different or distinctive for each well or facility), the name of the operator, current emergency phone number, file or facility number (if applicable), and the location by quarter-quarter, section, township, and range.

October 1, 2016; April 1, 2018; April 1, 2024.

History

• History: Amended effective January 1, 1983; May 1, 1992; September 1, 2000; April 1, 2014;

N.D. Admin. Code 43-02-03-18 Drilling units - Well locations

In the absence of an order by the commission setting spacing units for a pool: 1.a.Vertical or directional oil wells projected to a depth not deeper than the Mission Canyon formation must be drilled upon a governmental quarter-quarter section or equivalent lot, located not less than five hundred feet [152.4 meters] to the boundary of such governmental quarter-quarter section or equivalent lot. No more than one well shall be drilled to the same pool on any such governmental quarter-quarter section or equivalent lot, except by order of the commission, nor shall any well be drilled on any such governmental quarter-quarter section or equivalent lot containing less than thirty-six acres [14.57 hectares] except by order of the commission.

b.Vertical or directional oil wells projected to a depth deeper than the Mission Canyon formation must be drilled on a governmental quarter section or equivalent lots, located not less than six hundred sixty feet [201.17 meters] to the boundary of such governmental quarter section or equivalent lots. No more than one well shall be drilled to the same pool on any such governmental quarter section or equivalent lots, except by order of the commission, nor shall any well be drilled on any such governmental quarter

section or equivalent lots containing less than one hundred forty-five acres [58.68 hectares] except by order of the commission. 2.a.Horizontal wells with a horizontal displacement of the well bore drilled at an angle of at least eighty degrees within the productive formation of at least five hundred feet [152.4 meters], projected to a depth not deeper than the Mission Canyon formation, must be drilled upon a drilling unit described as a governmental section or described as two adjacent governmental quarter sections within the same section or equivalent lots, located not less than five hundred feet [152.4 meters] to the outside boundary of such tract. The horizontal well proposed to be drilled must, in the director's opinion, justify the creation of such drilling unit. No more than one well may be drilled to the same pool on any such tract, except by order of the commission.

b.Horizontal wells with a horizontal displacement of the well bore drilled at an angle of at least eighty degrees within the productive formation of at least five hundred feet [152.4 meters], projected to a depth deeper than the Mission Canyon formation, must be drilled upon a drilling unit described as a governmental section, or as adjacent governmental sections, located not less than five hundred feet [152.4 meters] to the outside boundary of such tract. The horizontal well proposed to be drilled must, in the director's opinion, justify the creation of such drilling unit. No more than one well may be drilled to the same pool on any such tract, except by order of the commission. 3.a.Gas wells projected to a depth not deeper than the Mission Canyon formation shall be drilled upon a governmental quarter section or equivalent lots, located not less than five hundred feet [152.4 meters] to the boundary of such governmental quarter section or equivalent lots. No more than one well may be drilled to the same pool on any such governmental quarter section or equivalent lots, except by order of the commission, nor shall any well be drilled on any such governmental quarter section or equivalent lot containing less than one hundred forty-five acres [58.68 hectares] except by order of the

b.Gas wells projected to a depth deeper than the Mission Canyon formation shall be drilled upon a governmental quarter section or equivalent lots, located not less than six hundred sixty feet [201.17 meters] to the boundary of such governmental quarter section or equivalent lots. No more than one well may be drilled to the same pool on any such governmental quarter section or equivalent lots, except by order of the commission, nor shall any well be drilled on any such governmental quarter section or equivalent lot containing less than one hundred forty-five acres [58.68 hectares] except by order of the 4.a.Within thirty days, or a reasonable time thereafter, following the discovery of oil or gas in a pool not then covered by an order of the commission, a spacing hearing must be docketed. Following such hearing the commission shall issue an order prescribing a temporary spacing pattern for the development of the pool. This order must continue in force for a period of not more than three years at the expiration of which time a hearing must be held at which the commission may require the presentation of such evidence as will enable the commission to determine the proper spacing for the pool.

b.During the interim period between the discovery and the issuance of the temporary order, no permits may be issued for the drilling of an offset well to the discovery well, unless approved by the director. Approval must be consistent with anticipated spacing for the orderly development of the pool.

c.Any well drilled within one mile [1.61 kilometers] of an established field shall conform to the spacing requirements in that field except when it is apparent that the well will not produce from the same common source of supply. In order to assure uniform and orderly development, any well drilled within one mile [1.61 kilometers] of an established field boundary must conform to the spacing and special field rules for the field, and for the purposes of spacing and pooling, the field boundary shall be extended to include the spacing unit for such well and any intervening lands. The foregoing is not applicable if it is apparent that the well will not produce from the same common source of supply as wells within the field.

5.If the director denies an application for permit, the director shall advise the applicant immediately of the reasons for denial. The decision of the director may be appealed to the

July 1, 2002; January 1, 2006; April 1, 2010; April 1, 2012; April 1, 2026.

If upon application for an exception location, the commission finds that a well drilled at the location prescribed by any applicable rule or order of the commission would not produce in paying quantities, that surface conditions would substantially add to the burden or hazard of such well, or that the drilling of such well at a location other than the prescribed location is otherwise necessary either to protect correlative rights, to prevent waste, or to effect greater ultimate recovery from oil and gas, the commission may enter an order, after notice and hearing, permitting the well to be drilled at a location other than that prescribed and shall include in such order suitable provisions to prevent the production from that well of more than its just and equitable share of the oil and gas in the pool. The application for an exception well location shall set forth the names of the lessees of adjoining properties and the names of any unleased mineral owners of the adjoining properties. The application shall be accompanied by a plat or sketch accurately showing the property for which the exception well location is sought, the location of the proposed well, and all other completed and drilling wells on this property and on the adjoining properties. The applicant or its attorney shall certify that a copy of the application has been sent to all lessees and all unleased mineral owners of properties adjoining the tract which would be affected by the exception location. If the applicant is the lessee of adjoining tracts that would be affected by the exception, the applicant must give notice, as prescribed above, to its lessors of such tracts.

January 1, 2008.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; May 1, 1994; July 1, 1996;
• Law Implemented: NDCC 38-08-04, 38-08-07 43-02-03-18.1. Exception location.
• History: Effective January 1, 1983; amended effective May 1, 1990; May 1, 1994; July 1, 1996;
• General Authority: NDCC 38-08-04, 38-08-07
• Law Implemented: NDCC 38-08-04, 38-08-07

N.D. Admin. Code 43-02-03-19 Site construction

1.In the construction of a well site, saltwater handling facility, treating plant, access road, and all associated facilities, the topsoil must be removed, stockpiled, and stabilized or otherwise reserved for use when the area is reclaimed. "Topsoil" means the suitable plant growth material on the surface; however, in no event is this deemed to be more than the top twelve inches [30.48 centimeters] of soil or deeper than the depth of cultivation, whichever is greater.

Soil stabilization materials, liners, fabrics, and other materials to be used onsite, on access roads or associated facilities, must be reported on a well or facility sundry notice to the director within thirty days after application. The reclamation plan for such materials must also be included.

2.If necessary to prevent pollution of the land surface and freshwaters, the director may require the site to be sloped and diked.

3.Sites may not be located in, or hazardously near, bodies of water, nor may they block natural drainages. Sites and associated facilities must be designed and built to be stable, divert surface drainage from entering the site, and prevent erosion. Sites exhibiting geotechnical instability causing or likely to cause movement sufficient to negatively impact existing or future infrastructure must be reported to the director immediately.

4.Sites or appropriate parts thereof must be fenced if required by the director.

5.Within six months after the completion of a well or construction of a saltwater handling facility or treating plant, the portion of the site not used for operations must be reclaimed, unless waived by the director. Operators shall file a well or facility sundry notice detailing the work that was performed and a current site diagram, which identifies the stockpiled topsoil location and its volume.

All open pits and ponds which contain saltwater must be fenced. All pits and ponds which contain oil must be fenced, screened, and netted.

This is not to be construed as requiring the fencing, screening, or netting of a drilling pit or reserve pit used solely for drilling, completing, recompleting, or plugging unless such pit is not reclaimed within ninety days after completion of drilling operations.

All waste material associated with exploration or production of oil and gas must be properly disposed of in an authorized facility in accordance with all applicable local, state, and federal laws and regulations.

All waste material recovered from spills, leaks, and other such events shall immediately be disposed of in an authorized facility, although the remediation of such material may be allowed onsite if approved by the director.

This is not to be construed as requiring the offsite disposal of drilling mud from shallow wells or drill cuttings associated with the drilling of a well. However, water remaining in a drilling or reserve pit used in the drilling and completion operations is to be removed from the pit and disposed of in an authorized disposal well or used in a manner approved by the director. The disposition or use of the water must be included on the sundry notice (form 4) reporting the plan of reclamation pursuant to sections 43-02-03-19.4 and 43-02-03-19.5.

Except as otherwise provided in this section and sections 43-02-03-19.4, 43-02-03-19.5, and 43-02-03-51.3, no saltwater, drilling mud, crude oil, waste oil, or other waste may be stored in earthen pits or open receptacles except in an emergency and upon approval by the director.

A lined earthen pit or open receptacle may be temporarily used to retain oil, water, cement, solids, or fluids generated in well plugging operations. A pit or receptacle used for this purpose must be sufficiently impermeable to provide adequate temporary containment of the oil, water, or fluids. The contents of the pit or receptacle must be removed within seventy-two hours after operations have ceased and must be disposed of at an authorized facility in accordance with section 43-02-03-19.2.

Within thirty days after operations have ceased, the earthen pit shall be reclaimed and the open receptacle shall be removed. The director may grant an extension of the thirty-day time period to no more than one year for good reason.

The director may permit pits or receptacles used solely for the purpose of flaring casinghead gas. A pit or receptacle used for this purpose must be sufficiently impermeable to provide adequate temporary containment of fluids. Permission for such pit or receptacle must be conditioned on locating the pit not less than one hundred fifty feet [45.72 meters] from the vicinity of wells and tanks and keeping it free of any saltwater, crude oil, waste oil, or other waste. Saltwater, drilling mud, crude oil, waste oil, or other waste must be removed from the pit or receptacle within twenty-four hours after being discovered and must be disposed of at an authorized facility in accordance with section 43-02-03-19.2.

The director may permit pits used solely for storage of freshwater used in completion and well servicing operations. Permit applications for freshwater pits must be submitted on a sundry notice and must be valid for a period of one year but may be reauthorized upon application. Freshwater pits must be lined and no pit constructed for this purpose may be wholly or partially constructed in fill dirt unless approved by the director. The director may approve chemical treatment to municipal drinking water standards upon application.

The freshwater pit must have signage on all sides accessible to vehicular traffic clearly identifying the usage as freshwater only.

The director may permit portable-collapsible receptacles used solely for storage of fluids used in completion and well servicing operations, although no flowback fluids may be allowed. Permit applications for such receptacles must be submitted on a sundry notice and must be valid for a period of one year but may be reauthorized upon application. Such receptacles must utilize a sealed inner bladder, erected to conform to American petroleum institute standards, and may not be wholly or partially constructed on fill dirt unless approved by the director. Such receptacles must have signage on all sides accessible to vehicular traffic clearly identifying the fluid contained within.

The director may permit portable-collapsible single sidewall, double liner open top receptacles used solely for storage of fluids used in completion and well servicing operations, although no flowback fluids may be allowed. Such receptacles must have signage on all sides accessible to vehicular traffic clearly identifying the fluid contained within. Permits for such receptacles must be submitted on a sundry notice and must be valid for a period of one year but may be reauthorized upon application. Permits for such receptacles must include at least the following information:

1.The name and address of the operator.

2.Legal location of the site where the open top receptacle will be located.

3.Structural engineering analysis of the open top receptacle including panels and connection system.

4.Schematic drawings depicting the following:

a.As-built or proposed cut and fill diagram showing how the open top receptacle will be located in a cut area of the site.

b.The site that includes its dimensions or proposed dimensions and the height, location, and calculated capacity of the perimeter berm and any other spill containment structures.

c.Fill pipe or filling mechanism designed to protect the liner system from the initial force of water entering the open top receptacle.

d.Isolation valves in the produced water and freshwater flow lines.

e.Location of the concrete jersey barriers around the open top receptacle to avert vehicular traffic and impede the flow of water in the event of a breach.

5.Descriptions of the following:

a.The double liner system including liner specifications.

b.Sand pad and geotextile liner used to protect the liner system.

c.Real-time leak detection and monitoring system, including between the liners and visual inspections.

d.Overfill and low-level detection systems.

e.Mechanical integrity testing plan using freshwater of the system.

f.Emergency plan for emptying the open top receptacle and addressing resources on standby in the event of a breach.

g.Estimated setup and deconstruction dates.

The director may docket the permit application for hearing to gather additional information necessary to evaluate the proposed open top receptacle and site.

Permits may contain such terms and conditions as the director deems necessary.

Any permit issued under this section may be revoked by the commission after notice and hearing if the permittee fails to comply with the terms and conditions of the permit, any directive of the director, or any applicable rule or statute.

Any permit issued under this section may be modified or suspended by the director for good cause.

Permits are transferable only with approval of the director.

April 1, 2020; April 1, 2024. 43-02-03-19.4. Drilling pits.

A pit may be utilized to bury drill cuttings and solids generated during well drilling and completion operations, providing the pit can be constructed, used, and reclaimed in a manner that will prevent pollution of the land surface and freshwaters. In special circumstances, the director may prohibit construction of a cuttings pit or may impose more stringent pit construction and reclamation requirements. Reserve and circulation of mud system through earthen pits are prohibited unless a waiver is granted by the director. All pits shall be inspected by an authorized representative of the director prior to lining and use. Under no circumstances shall pits be used for disposal, dumping, or storage of fluids, wastes, and debris other than drill cuttings and solids recovered while drilling and completing the well.

Drill cuttings and solids must be stabilized in a manner approved by the director prior to placement in a cuttings pit. Any liquid accumulating in the cuttings pit shall be promptly removed. The pit shall be diked in a manner to prevent surface water from running into the pit.

A small lined pit can be authorized by the director for temporary containment of incidental fluids such as trench water and rig wash, if emptied and covered prior to the rig leaving the site.

Pits shall not be located in, or hazardously near, bodies of water, nor shall they block natural drainages. No pit shall be wholly or partially constructed in fill dirt unless approved by the director.

When required by the director, the drilling pit or appropriate parts thereof shall be fenced.

Within thirty days after the drilling of a well or expiration of a drilling permit, drilling pits shall be reclaimed. The director may grant an extension of the thirty-day time period to no more than one year for good reason. Prior to reclaiming the pit, the operator or the operator's agent shall obtain verbal approval from the director of a pit reclamation plan.

A subsequent sundry notice (form 4) shall be filed detailing the pit reclamation and shall include:

1.The name and address of the reclamation contractor;

2.The name and address of the surface owner; and

3.A description of the work completed, including details on treatment and disposition of the drilling waste.

Any water or oil accumulated on the pit must be removed prior to reclamation. Drilling waste shall be encapsulated in the pit and covered with at least four feet [1.22 meters] of backfill and topsoil and surface sloped, when practicable, to promote surface drainage away from the reclaimed pit area.

For wells drilled to a strata or formation, including lignite or coal strata or seam, located above the depth of five thousand feet [1524 meters] below the surface, or located more than five thousand feet [1524 meters] below the surface but above the top of the Rierdon formation, a container or reserve pit of sufficient size to contain said material or fluid, and the accumulation of drill cuttings may be utilized to contain solids and fluids used and generated during well drilling and completion operations, providing the pit can be constructed, used and reclaimed in a manner that will prevent pollution of the land surface and freshwaters. A reserve pit may be allowed by an order of the commission after notice and hearing, provided the reserve pit can be constructed, used, and reclaimed in a manner that will prevent pollution of the land surface and freshwaters, for (a) wells drilled within a specified field and pool more than five thousand feet [1524 meters] below the surface and below the top of the Rierdon formation provided the proposed well or wells utilized a low sodium content water-based mud system or (b) for wells drilled and completed, outside an established field which has defined the pool to include the Bakken or Three Forks formation, when separate reserve pits will be utilized to segregate each mud system and associated drill cuttings and any oil skim accumulated on any reserve pit utilized for a water-based mud system will be removed immediately after completion of drilling operations so as not to cause any significant delay in the reclamation of the reserve pit. In special circumstances, based on site-specific conditions, the director or authorized representative may prohibit construction of a reserve pit or may impose more stringent pit construction and reclamation requirements, including reserve pits previously authorized by a commission order within a specified field and pool. Under no circumstances shall reserve pits be used for disposal, dumping, or storage of fluids, wastes, and debris other than drill cuttings and fluids used or recovered while drilling and completing the well.

Reserve pits shall not be located in, or hazardously near, bodies of water, nor shall they block natural drainages. No reserve pit shall be wholly or partially constructed in fill dirt unless approved by Within a reasonable time, but not more than one year after the completion of a shallow well, or prior to drilling below the surface casing shoe on any other well, the reserve pit shall be reclaimed. Prior to reclaiming the pit, the operator or the operator's agent shall file a sundry notice (form 4) with the director and obtain approval of a pit reclamation plan. Verbal approval to reclaim the pit may be given.

The notice shall include:

1.The name and address of the reclamation contractor;

2.The name and address of the surface owner;

3.The location and name of the disposal site for the pit water; and

4.A description of the proposed work, including details on treatment and disposition of the drilling waste.

All pit water must be removed prior to reclamation. Drilling waste should be encapsulated in the pit and covered with at least four feet [1.22 meters] of backfill and topsoil and surface sloped, when practicable, to promote surface drainage away from the reclaimed pit area.

History

• History: Amended effective March 1, 1982; January 1, 1983; May 1, 1992; July 1, 2002; January 1, 2008; April 1, 2010; April 1, 2012; April 1, 2014; October 1, 2016; April 1, 2026. 43-02-03-19.1. Fencing, screening, and netting of drilling and reserve pits.
• History: Effective May 1, 1992; amended effective April 1, 2012. 43-02-03-19.2. Disposal of waste material.
• History: Effective May 1, 1992; amended effective May 1, 1994; September 1, 2000; April 1, 2012. 43-02-03-19.3. Earthen pits and receptacles.
• History: Effective September 1, 2000; amended effective April 1, 2010; April 1, 2012; October 1, 2016;
• History: Effective April 1, 2012; amended effective April 1, 2014. 43-02-03-19.5. Reserve pit for drilling mud and drill cuttings from shallow wells.
• History: Effective April 1, 2012; amended effective April 1, 2014.

N.D. Admin. Code 43-02-03-20 Sealing off strata

During the drilling of any well, all oil, gas, and water strata must be sealed or separated where necessary in order to prevent their contents from passing into other strata.

All freshwaters and waters of present or probable value for domestic, commercial, or stock purposes must be confined to their respective strata and must be adequately protected by methods approved by the director. Special precautions must be taken in drilling and plugging wells to guard against any loss of artesian water from the strata in which it occurs and the contamination of artesian water by objectionable water, oil, or gas.

All water must be shut off and excluded from the various oil-bearing and gas-bearing strata which are penetrated. Water shutoffs ordinarily must be made by cementing casing or landing casing with or without the use of mud-laden fluid.

History

• History: Amended effective May 1, 1992; April 1, 2024.

N.D. Admin. Code 43-02-03-21 Casing, tubing, and cementing requirements

1.All wells drilled must be constructed with strings of casing which must be properly cemented at sufficient depths to adequately protect and isolate all formations containing water, oil, or gas or any combination of these; protect the pipe through salt sections encountered; and isolate the uppermost sand of the Dakota group. Cementing must be by the pump and plug method while the drilling rig is on the well or other methods approved by the director.

2.Drilling of the surface hole must be with freshwater-based drilling mud or other method approved by the director which protects all freshwater-bearing strata. This includes water used during the cementing of surface casing for displacement. The surface casing must consist of new or reconditioned pipe that has been previously tested to one thousand pounds per square inch [6900 kilopascals]. The surface casing must be set and cemented at a point not less than fifty feet [15.24 meters] below the base of the Fox Hills formation. Sufficient cement must be used on surface casing to fill the annular space behind the casing to the bottom of the cellar, if any, or to the surface of the ground. If the annulus space is not adequately filled with cement, the director must be notified immediately. The operator shall diligently perform remedial work after obtaining approval from the director. All strings of surface casing must stand cemented under pressure for at least twelve hours before drilling the plug. The term "under pressure" as used herein must be complied with if one float valve is used or if pressure is otherwise held.

An appropriate accurate gauge must be maintained on the surface casing of any well, not properly plugged and abandoned, to detect any buildup of pressure caused by the migration of fluids. Surface casing pressure must be monitored and maintained to keep the hydrostatic pressure at the surface casing shoe below the pressure the formation integrity test was performed at.

3.Surface casing strings must be allowed to stand under pressure until the tail cement has reached a compressive strength of at least five hundred pounds per square inch [3450 kilopascals]. All filler cements utilized must reach a compressive strength of at least two hundred fifty pounds per square inch [1725 kilopascals] within twenty-four hours and at least three hundred fifty pounds per square inch [2415 kilopascals] within seventy-two hours. All compressive strengths on surface casing cement must be calculated at a temperature of eighty degrees Fahrenheit [26.67 degrees Celsius].

4.Production or intermediate casing strings must consist of new or reconditioned pipe that has been previously tested to two thousand pounds per square inch [13800 kilopascals]. Such strings must be allowed to stand under pressure until the tail cement has reached a compressive strength of at least five hundred pounds per square inch [3450 kilopascals]. All filler cements utilized must reach a compressive strength of at least two hundred fifty pounds per square inch [1725 kilopascals] within twenty-four hours and at least five hundred pounds per square inch [3450 kilopascals] within seventy-two hours, although in any horizontal well performing a single stage cement job from a measured depth of greater than thirteen thousand feet [3962.4 meters], the filler cement utilized must reach a compressive strength of at least two hundred fifty pounds per square inch [1725 kilopascals] within forty-eight hours and at least five hundred pounds per square inch [3450 kilopascals] within ninety-six hours. All compressive strengths on production or intermediate casing cement must be calculated at a temperature found in the Mowry formation using a gradient of 1.2 degrees Fahrenheit per one hundred feet [30.48 meters] of depth plus eighty degrees Fahrenheit [26.67 degrees Celsius].

At a formation temperature at or in excess of two hundred thirty degrees Fahrenheit [110 degrees Celsius], cement blends must include additives to address compressive strength regression.

5.Each surface casing string must be tested by application of pump pressure of at least one thousand pounds per square inch [6900 kilopascals] and each other casing string shall be tested by application of pump pressure of at least one thousand five hundred pounds per square inch [10350 kilopascals] immediately after cementing, while the cement is in a liquid state, or the casing string must be pressure tested after all cement has reached five hundred pounds per square inch [3450 kilopascals] compressive strength. If, at the end of thirty minutes, this pressure has dropped more than ten percent, the casing must be repaired after receiving approval from the director. Thereafter, the casing again must be tested in the same manner. Further work may not proceed until a satisfactory test has been obtained. The casing in a horizontal well may be tested by use of a mechanical tool set near the casing shoe after the horizontal section has been drilled.

6.All flowing wells must be equipped with tubing. A tubing packer must also be utilized unless a waiver from the director is obtained after demonstrating the casing will not be subjected to excessive pressure or corrosion. The packer must be set as near the producing interval as practicable, but in all cases must be above the perforations.

April 1, 2020; April 1, 2022; April 1, 2024; April 1, 2026.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; July 1, 1996; January 1, 1997; September 1, 2000; July 1, 2002; May 1, 2004; January 1, 2006; April 1, 2010; April 1, 2012;

N.D. Admin. Code 43-02-03-22 Defective casing or cementing

1.In any well that appears to have defective casing or cementing, the operator shall report the defect to the director verbally and file a well sundry notice if required by the director. To properly evaluate the condition of the well, the operator shall diligently conduct tests or run logs as approved or required by the director. Prior to attempting remedial work to correct any defect, the operator shall obtain approval from the director. The director is authorized to require subsequent pressure tests and logs to verify casing integrity if its competence is questionable. The director may allow the well condition to remain if correlative rights can be protected without endangering potable waters. The well must be properly plugged if requested by the director.

2.After any attempted or completed remedial work, a report on the operation must be filed on a well sundry notice with the director pursuant to section 43-02-03-31.

3.Any well with open perforations above a packer is considered to have defective casing.

History

• History: Amended effective January 1, 1983; May 1, 1992; September 1, 2000; July 1, 2002; May 1, 2004; January 1, 2008; April 1, 2018; April 1, 2026.

N.D. Admin. Code 43-02-03-23 Blowout prevention

In all drilling operations, proper and necessary precautions shall be taken for keeping the well under control, including the use of a blowout preventer and high pressure fittings attached to properly cemented casing strings adequate to withstand anticipated pressures. During the course of drilling, the pipe rams shall be functionally operated at least once every twenty-four-hour period. The blind rams shall be functionally operated each trip out of the well bore. The blowout preventer shall be pressure tested at installation on the wellhead, after modification of any equipment, and every thirty days thereafter. For pad drilling operations, moving from one wellhead to another within the thirty days, pressure testing is required on connections when the integrity of a pressure seal is broken or a component appears to be damaged or compromised. The director may postpone such pressure test if the necessity therefor can be demonstrated to the director's satisfaction. All tests shall be noted in the driller's record.

In all workover operations, proper and necessary precautions must be taken for keeping the well under control, including the use of a blowout preventer and high pressure fittings attached to properly cemented casing strings adequate to withstand anticipated pressures.

History

• History: Amended effective January 1, 1983; September 1, 2000; July 1, 2002; April 1, 2020.

N.D. Admin. Code 43-02-03-24 Pulling string of casing

In pulling strings of casing from any well, the space above the casing stub must be kept and left full of fluid with adequate gel strength and specific gravity, cement, or combination thereof, to seal off all freshwater and saltwater strata and any strata bearing oil or gas not producing. No casing may be removed without the prior approval of the director.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; April 1, 2024.

N.D. Admin. Code 43-02-03-25 Deviation tests and directional surveys

When any well is drilled or deepened, tests to determine the deviation from the vertical shall be taken at least every one thousand feet [304.8 meters]. The director is authorized to waive the deviation test for a shallow gas well if the necessity therefor can be demonstrated to the director's satisfaction.

When the deviation from the vertical exceeds five degrees at any point, the director may require that the hole be straightened. Directional surveys may be required by the director, whenever, in the director's judgment, the location of the bottom of the well is in doubt.

A directional survey shall be made and filed with the director on any well utilizing a whipstock or any method of deviating the well bore. The obligation to run the directional survey may be waived by the director when a well bore is deviated to sidetrack junk in the hole, straighten a crooked hole, control a blowout, or if the necessity therefor can be demonstrated to the director's satisfaction. The survey contractor shall file with the director free of charge one certified electronic copy of all surveys, in a form approved by the director, within thirty days of attaining total depth. Such survey shall be in reference to true north. The director may require the directional survey to be filed immediately after completion if the survey is needed to conduct the operation of the director's office in a timely manner. Special permits may be obtained to drill directionally in a predetermined direction as provided above, from the director.

If the director denies a request for a permit to directionally drill, the director shall advise the applicant immediately of the reasons for denial. The decision of the director may be appealed to the

May 1, 1994; September 1, 2000; January 1, 2006; April 1, 2010; April 1, 2012.

History

• History: Amended effective April 1, 1980; April 30, 1981; January 1, 1983; May 1, 1990; May 1, 1992;

N.D. Admin. Code 43-02-03-26 Multiple zone completions

Multiple zone completions in any pool may be permitted by the director.

An application for a multiple zone completion shall be accompanied by an exhibit showing the location of all wells on the applicant's lease and all offset wells on offset leases and shall set forth all material facts on the common sources of supply involved and the manner and method of completion proposed.

Multiple completed wells shall at all times be operated, produced, and maintained in a manner to ensure the complete segregation of the various common sources of supply. The director may require such tests as the director deems necessary to determine the effectiveness of the segregation of the different sources of supply.

History

• History: Amended effective January 1, 1983; May 1, 1992.

N.D. Admin. Code 43-02-03-27 Perforating, fracturing, and chemically treating wells

The director may prescribe pretreatment casing pressure testing as well as other operational requirements designed to protect wellhead and casing strings during treatment operations. If damage results to the casing or the casing seat from perforating, fracturing, or chemically treating a well, the operator shall immediately notify the director and proceed with diligence to use the appropriate method and means for rectifying such damage, pursuant to section 43-02-03-22. If perforating, fracturing, or chemical treating results in irreparable damage which threatens the mechanical integrity of the well, the commission may require the operator to plug the well.

1.Prior to performing any hydraulic fracture stimulation, including refracs, through a frac string run inside the casing string:

a.Remedial work must be performed on all casing strings deemed defective pursuant to

section 43-02-03-22 prior to performance at the discretion of the director.

b.The frac string must be either stung into a liner with the hanger/packer located in cemented casing or run with a packer set at a minimum depth of one hundred feet [30.48 meters] below the top of cement or a minimum depth of one hundred feet [30.48 meters] below the top of the Inyan Kara formation, whichever is deeper.

c.The casing-frac string annulus must be pressurized and monitored during frac operations. If there is a suspected frac string or casing failure, the operator of the well shall verbally notify the director as soon as practicable.

d.An adequately sized, function tested pressure relief valve must be utilized on the treating lines from the pumps to the wellhead, with suitable check valves to limit the volume of flowback fluid should the relief valve open. The relief valve must be set to limit line pressure to no more than eighty-five percent of the internal yield pressure of the frac string.

e.An adequately sized, function tested pressure relief valve and an adequately sized diversion line must be utilized to divert flow from the casing to a pit or containment vessel in case of frac string failure. The relief valve must be set to limit annular pressure to no more than eighty-five percent of the lowest internal yield pressure of the casing string or no greater than the pressure test on the intermediate casing, less one hundred pounds per square inch gauge, whichever is less.

f.The surface casing must be fully open and connected to a diversion line rigged to a pit or containment vessel.

g.An adequately sized, function tested remote operated frac valve must be utilized at a location on the christmas tree that provides isolation of the well bore from the treating line and must be remotely operated from the edge of the location or other safe distance.

h.The director must be notified within twenty-four hours after the commencement of hydraulic fracture stimulation operations, in an electronic format approved by the director, identifying the subject well and verifying a frac string was run in the well.

i.Within sixty days after the hydraulic fracture stimulation is performed, the owner, operator, or service company shall post on the fracfocus chemical disclosure registry all elements made viewable by the fracfocus website.

2.Prior to performing any hydraulic fracture stimulation, including refracs, through a casing string:

a.Remedial work must be performed on all casing strings deemed defective pursuant to

section 43-02-03-22 prior to performance at the discretion of the director.

b.The maximum treating pressure may not be greater than eighty-five percent of the American petroleum institute rating of the affected casing string.

c.Casing evaluation tools to verify adequate wall thickness of any affected casing string must be run from the wellhead to a depth as close as practicable to one hundred feet [30.48 meters] above the completion formation and a visual inspection with photographs must be made of the top joint of the casing and the wellhead flange. The visual inspection and photograph requirement may be waived by the director for good cause.

If the casing evaluation tool or visual inspection indicates wall thickness is below the American petroleum institute minimum or a lighter weight of casing than the well design called for, calculations must be made to determine the reduced pressure rating. If the reduced pressure rating is less than the anticipated treating pressure, a frac string must be run inside the casing.

d.Cement evaluation tools to verify adequate cementing of each casing string shall be run from the wellhead to a depth as close as practicable to one hundred feet [30.48 meters] above the completion formation.

(1)If the cement evaluation tool indicates defective casing or cementing, a frac string must be run inside the casing.

(2)If the cement evaluation tool indicates the casing string cemented in the well fails to satisfy section 43-02-03-21, a frac string must be run inside the casing.

e.Each affected casing string and the wellhead must be pressure tested for at least thirty minutes with less than five percent loss to a pressure equal to or in excess of the maximum frac design pressure.

f.If the pressure rating of the wellhead does not exceed the maximum frac design pressure, a wellhead and blowout preventer protection system must be utilized during the frac.

g.An adequately sized, function tested pressure relief valve must be utilized on the treating lines from the pumps to the wellhead, with suitable check valves to limit the volume of flowback fluid should be the relief valve open. The relief valve must be set to limit line pressure to no greater than the test pressure of the casing, less one hundred pounds per square inch [689.48 kilopascals].

h.The surface casing value must be fully open and connected to a diversion line rigged to a pit or containment vessel.

i.An adequately sized, function tested remote operated frac valve must be utilized between the treating line and the wellhead.

j.If there is a suspected casing failure, the operator of the well shall verbally notify the director as soon as practicable.

k.Notify the director within twenty-four hours after the commencement of hydraulic fracture stimulation operations, in an electronic format approved by the director, identifying the subject well and verifying all logs and pressure tests have been performed as required.

l.Within sixty days after the hydraulic fracture stimulation is performed, the owner, operator, or service company shall post on the fracfocus chemical disclosure registry all elements made viewable by the fracfocus website.

3.If during the stimulation, an unexpected pressure loss or other unexpected event occurs suggesting loss of containment, or the pressure in the casing-surface casing annulus exceeds three hundred fifty pounds per square inch [2413 kilopascals] gauge, the owner or operator verbally shall notify the director as soon as practicable but no later than twenty-four hours following the incident.

History

• History: Amended effective January 1, 1983; May 1, 1992; April 1, 2010. 43-02-03-27.1. Hydraulic fracture stimulation.
• History: Effective April 1, 2012; amended effective April 1, 2014; April 1, 2020; April 1, 2022; April 1,

N.D. Admin. Code 43-02-03-28 Safety regulation

1.During drilling operations all oil wells must be cleaned into a pit or tank, not less than forty feet [12.19 meters] from the derrick floor and one hundred fifty feet [45.72 meters] from any fire hazard.

2.All flowing oil wells must be produced through an approved oil and gas separator or emulsion treater of ample capacity and in good working order. No boiler, electric generator, flare, or treater may be placed nearer than one hundred fifty feet [45.72 meters] to any producing well or oil tank that is not an oil processing vessel as defined in American Society of Mechanical Engineers (ASME) section VIII. Placement as close as one hundred twenty-five feet [38.10 meters] may be allowed if a spark or flame arrestor is utilized on the equipment. Placement of an oil processing vessel as defined in ASME section VIII as close as fifty feet [15.24 meters] may be allowed if approved by the director. The required distances above must be measured horizontally from closest vessel edge to closest edge of the boiler, generator, flare, or treater or closest vessel edge to flame arrestor or burner air inlet edge. Any rubbish or debris that might constitute a fire hazard must be removed to a distance of at least one hundred fifty feet [45.72 meters] from the vicinity of wells and tanks. All waste must be burned or disposed of in such manner as to avoid creating a fire hazard. All vegetation must be removed to a safe distance from any production or injection equipment to eliminate a fire hazard.

3.The director may require remote operated or automatic shutdown equipment to be installed on, or shut in for no more than forty days, any well that is likely to cause a serious threat of wildfire, pollution, or injury to the public health and safety.

4.Surface casing may not be plumbed into the production flow line to relieve pressure without approval from the director.

5.A well may not be drilled nor production or injection equipment installed and a saltwater handling facility or treating plant may not be constructed less than five hundred feet [152.40 meters] from an occupied dwelling unless agreed to in writing by the owner of the dwelling or authorized by order of the commission.

6.Subsurface pressure must be controlled during all drilling, completion, and well-servicing operations with appropriate fluid weight and pressure control equipment. The operator conducting any well hydraulic fracture stimulation shall give prior written notice, up to thirtyone days and not less than twenty-one days, to any operator of a well completed in the same or adjacent pool, if publicly available information indicates or if the operator is made aware, if the completion intervals are within two thousand six hundred and forty feet [804.67 meters] of one another. Notice must include twenty-four-hour emergency contact information, planned start and end dates, and contact information for scheduling updates.

January 1, 2008; April 1, 2012; April 1, 2014; October 1, 2016; April 1, 2020; April 1, 2024; April 1, 2026.

History

• History: Amended effective January 1, 1983; May 1, 1990; September 1, 2000; January 1, 2006;
• Law Implemented: NDCC 38-08-04, 38-08-04.4

N.D. Admin. Code 43-02-03-29 Well and lease equipment and gas gathering pipelines

1.Wellhead and lease equipment with a working pressure at least equivalent to the calculated or known pressure to which the equipment may be subjected must be installed and maintained.

Equipment on producing wells must be installed to facilitate gas-oil ratio tests, and static bottom hole or other pressure tests. Valves must be installed and maintained in good working order to permit pressure readings to be obtained on both casing and tubing.

2.All newly constructed underground gas gathering pipelines must be devoid of leaks and constructed of materials resistant to external corrosion and to the effects of transported fluids.

All such pipelines installed in a trench must be installed in a manner that minimizes interference with agriculture, road and utility construction, the introduction of secondary stresses, the possibility of damage to the pipe, and tracer wire shall be buried with any nonconductive pipes installed. When a trench for an underground gas gathering pipeline is backfilled, it must be backfilled in a manner that provides firm support under the pipe and prevents damage to the pipe and pipe coating from equipment or from the backfill material.

a.The operator of any underground gas gathering pipeline placed into service on August 1, 2011, to June 30, 2013, shall file with the director, by January 1, 2015, a geographical information system layer utilizing North American datum 83 geographic coordinate system (GCS) and in an environmental systems research institute (Esri) shape file format showing the location of the pipeline centerline. Any shape files that have been created for any underground gas gathering pipeline placed into service prior to August 1, 2011, must also be filed with the director. The operator of any underground gas gathering pipeline placed into service after June 30, 2013, shall file with the director, within one hundred eighty days of placing into service, a geographical information system layer utilizing North American datum 83 geographic coordinate system (GCS) and in an environmental systems research institute (Esri) shape file format showing the location of all compressor sites, buried drip tanks, and the pipeline centerline. An affidavit of completion must accompany each layer containing the following information:

(1)A statement that the pipeline was constructed and installed in compliance with

section 43-02-03-29.

(2)The outside diameter, minimum wall thickness, composition, internal yield pressure, and maximum temperature rating of the pipeline, or any other specifications deemed necessary by the director.

(3)The anticipated operating pressure of the pipeline.

(4)The type of fluid that will be transported in the pipeline and direction of flow.

(5)Pressure to which the pipeline was tested prior to placing into service.

(6)The minimum pipeline depth of burial.

(7)In-service date.

(8)Leak detection and monitoring methods that will be utilized after in-service date.

(9)Pipeline name.

(10)Accuracy of the geographical information system layer.

b.If an underground gas gathering pipeline or any part of such pipeline is abandoned, the operator shall leave such pipeline in a safe condition by conducting the following:

(1)Disconnect and physically isolate the pipeline from any operating facility or other pipeline.

(2)Cut off the pipeline or the part of the pipeline to be abandoned below surface at pipeline level.

(3)Purge the pipeline with fresh water, air, or inert gas in a manner that effectively removes all fluid.

(4)Remove cathodic protection from the pipeline.

(5)Permanently plug or cap all open ends by mechanical means or welded means.

3.Within one hundred eighty days of completing the abandonment of an underground gas gathering pipeline the operator of the pipeline shall file with the director a geographical information system layer utilization North American datum 83 geographic coordinate system (GCS) and in an environmental systems research institute (Esri) shape file format showing the location of the pipeline centerline and an affidavit of completion containing the following information:

a.A statement that the pipeline was abandoned in compliance with section 43-02-03-29.

b.The type of fluid used to purge the pipeline.

4.Aboveground pipeline markers must be placed and maintained over each buried underground gas gathering pipeline or portion thereof at the discretion of the director when necessary to protect public health and safety. The markers must contain at least the following on a background of sharply contrasting color: the word "Warning", "Caution", or "Danger" followed by the fluid transported pipeline, the name of the operator, and current emergency phone number.

The requirement to submit a geographical information system layer may not be construed to be required on buried piping utilized to connect flares, tanks, treaters, or other equipment located entirely within the boundary of a well site or production facility.

1.Application of section. This section is applicable to all underground gathering pipelines designed for or capable of transporting crude oil or produced water from an oil and gas production facility for the purpose of disposal, storage, or for sale purposes. If these rules differ from the pipeline manufacturer's prescribed installation and operation practices, the pipeline manufacturer's prescribed installation and operation practices take precedence.

The requirements in this section are not applicable to flow lines, injection pipelines, pipelines operated by an enhanced recovery unit for enhanced recovery unit operations, or on piping utilized to connect wells, tanks, treaters, flares, or other equipment located entirely within the boundary of a well site or production facility.

If these rules differ from or are preempted by federal requirements on federally regulated pipelines, the federal rules take precedence. The pipeline owner shall provide sufficient documentation to the director confirming the pipeline is federally regulated.

2.Definitions. The terms used throughout this section apply to this section only.

a."Crude oil or produced water underground gathering pipeline" means an underground gathering pipeline designed or intended to transfer crude oil or produced water from a production facility for disposal, storage, or sale purposes.

b."New construction" means a new gathering pipeline installation project or an alteration or reroute of an existing gathering pipeline where the location, composition, size, design temperature, or design pressure changes.

c."Pipeline repair" is the work necessary to restore a pipeline system to a condition suitable for safe operations that does not change the design temperature or pressure.

d."Gathering system" is a group of connected pipelines which have been designated as a gathering system by the operator. A gathering system must have a unique name and must be interconnected.

e."In-service date" is the first date fluid was transported down the underground gathering pipeline for disposal, storage, or sale purposes after construction.

3.Notifications.

a.The underground gathering pipeline owner shall notify the director, at least seven days prior to commencing new construction of any underground gathering pipeline. The notice of intent to construct automatically expires after one year and for any project not built within one year; a new notice of intent to construct must be submitted.

(1)The notice of intent to construct a crude oil or produced water underground gathering pipeline must include the following:

(a)The proposed date construction is scheduled to begin.

(b)A statement that the director will be verbally notified approximately forty-eight hours prior to commencing the construction.

(c)A geographical information system layer utilizing North American datum 83 geographic coordinate system (GCS) and in an environmental systems research institute (Esri) shape file format showing the proposed route of the pipeline from the point of origin to the termination point.

(d)The proposed underground gathering pipeline design drawings, including all associated above ground equipment. [1]The proposed pipeline composition, specifications (i.e. size, weight, grade, wall thickness, coating, and standard dimension ratio). [2]The type of fluid to be transported. [3]The method of testing pipeline integrity (e.g. hydrostatic or pneumatic test) prior to placing the pipeline into service. [4]Proposed burial depth of the pipeline. [5]The location and type of all road crossings (i.e. bored and cased or bored only). [6]The location of all environmentally sensitive areas, such as wetlands, streams, or other surface waterbodies that the pipeline may traverse, if applicable.

b.The underground gathering pipeline owner shall file a sundry notice (form 4 or form provided by the director) with the director providing notification of any underground gathering pipeline system or portion thereof that has been removed from service for more than one year.

c.If damage occurs to any underground gathering pipeline, flow line, or other underground equipment used to transport crude oil, natural gas, carbon dioxide, or water produced in association with oil and gas, during construction, operation, maintenance, repair, or abandonment of an underground gathering pipeline, the responsible party shall verbally notify the director immediately.

d.The pipeline owner shall file a sundry notice (form 4 or form provided by the director) within thirty days of the in-service date reporting the date of first service.

4.Design and construction.

The following applies to newly constructed crude oil and produced water underground gathering pipelines, including tie-ins to existing systems:

a.Underground gathering pipelines must be devoid of leaks and constructed of materials resistant to external corrosion and to the effects of transported fluids.

b.Underground gathering pipelines must be designed in a manner that allows for line maintenance, periodic line cleaning, and integrity testing.

c.Installation crews must be trained in all installation practices for which they are tasked to perform.

d.Underground gathering pipelines must be installed in a manner that minimizes interference with agriculture, road and utility construction, the introduction of secondary stresses, and the possibility of damage to the pipe. Tracer wire must be buried with any nonconductive pipe installed.

e.Unless the manufacturer's installation procedures and practices provide guidance, pipeline trenches must be constructed to allow for the pipeline to rest on undisturbed native soil and provide continuous support along the length of the pipe. Trench bottoms must be free of rocks greater than two inches in diameter, debris, trash, and other foreign material not required for pipeline installation. If a trench bottom is over excavated, the trench bottom must be backfilled with appropriate material and compacted prior to installation of the pipe to provide continuous support along the length of the pipe.

The width of the trench must provide adequate clearance on each side of the pipe.

Trench walls must be excavated to ensure minimal sluffing of sidewall material into the trench. Subsoil from the excavated trench must be stockpiled separately from previously stripped topsoil.

f.Underground gathering pipelines that cross a township, county, or state graded road must be bored unless the responsible governing agency specifically permits the owner to open cut the road.

g.No pipe or other component may be installed unless it has been visually inspected at the site of installation to ensure that it is not damaged in a manner that could impair its strength or reduce its serviceability.

h.The pipe must be handled in a manner that minimizes stress and avoids physical damage to the pipe during stringing, joining, or lowering in. During the lowering in process the pipe string must be properly supported so as not to induce excess stresses on the pipe or the pipe joints or cause weakening or damage to the outer surface of the pipe.

i.When a trench for an underground gathering pipeline is backfilled, it must be backfilled in a manner that provides firm support under the pipe and prevents damage to the pipe and pipe coating from equipment or from the backfill material. Sufficient backfill material must be placed in the haunches of the pipe to provide long-term support for the pipe. Backfill material that will be within two feet of the pipe must be free of rocks greater than two inches in diameter and foreign debris. Backfilling material must be compacted as appropriate during placement in a manner that provides support for the pipe and reduces the potential for damage to the pipe and pipe joints.

j.Cover depths must be a minimum of four feet [1.22 meters] from the top of the pipe to the finished grade. The cover depth for an undeveloped governmental section line must be a minimum of six feet [1.83 meters] from the top of the pipe to the finished grade.

k.Underground gathering pipelines that traverse environmentally sensitive areas, such as wetlands, streams, or other surface waterbodies, must be installed in a manner that minimizes impacts to these areas. Any horizontal directional drilling plan prepared by the owner or required by the director, must be filed with the director, prior to the commencement of horizontal directional drilling.

l.Clamping or squeezing as a method of connecting any produced water underground gathering pipeline must be approved by the director. Prior to clamping or squeezing the pipeline, the owner shall file a sundry notice (form 4 or form provided by the director) with the director and obtain approval of the clamping or squeezing plan. The notice must include documentation that the pipeline can be safely clamped or squeezed as prescribed by the manufacturer's specifications. Any damaged portion of a produced water underground gathering pipeline that has been clamped or squeezed must be replaced before it is placed into service.

5.Pipeline reclamation.

a.When utilizing excavation for pipeline installation, repair, or abandonment, topsoil must be stripped, segregated from the subsoils, and stockpiled for use in reclamation.

"Topsoil" means the suitable plant growth material on the surface; however, in no event shall this be deemed to be more than the top twelve inches [30.48 centimeters] of soil or deeper than the depth of cultivation, whichever is greater.

b.The pipeline right-of-way must be reclaimed as closely as practicable to original condition. All stakes, temporary construction markers, cables, ropes, skids, and any other debris or material not native to the area must be removed from the right-of-way and lawfully disposed of.

c.During right-of-way reclamation all subsoils and topsoils must be returned in proper order to as close to the original depths as practicable. Right-of-way reclamation must be completed within one year of the pipeline being placed into service. An extension may be granted at the director's discretion.

d.The reclaimed right-of-way soils must be stabilized to prevent excessive settling, sluffing, cave-ins, or erosion.

e.The crude oil and produced water underground gathering pipeline owner is responsible for their right-of-way reclamation and maintenance until such pipeline is released by the director from the pipeline bond pursuant to section 43-02-03-15.

6.Inspection.

All newly constructed crude oil and produced water underground gathering pipelines must be inspected by third-party independent inspectors to ensure the pipeline is installed as prescribed by the manufacturer's specifications and in accordance with the requirements of this section. A list of all third-party independent inspectors and a description of each independent inspector's qualifications, certifications, experience, and specific training must be provided to the director upon request. A person may not be used to perform inspections unless that person has been trained and is qualified in the phase of construction to be inspected. The third-party independent inspector may not be an employee of the gathering pipeline owner/operator or the contractor hired to construct and install the pipeline. The number of third-party independent inspectors must be adequate for the size of the pipeline construction project to ensure proper pipeline installation.

7.Associated pipeline facility.

No associated above ground equipment may be installed less than five hundred feet [152.40 meters] from an occupied dwelling unless agreed to in writing by the owner of the dwelling or authorized by order of the commission.

All associated above ground equipment used to store crude oil or produced water must be devoid of leaks and constructed of materials resistant to the effects of crude oil, produced water, brines, or chemicals that may be contained therein. The above materials requirement may be waived by the director for tanks presently in service and in good condition. Unused tanks and associated above ground equipment must be removed from the site or placed into service, within a reasonable time period, not to exceed one year.

Dikes must be erected around all produced water or crude oil tanks at any new facility prior to placing the associated underground gathering pipeline into service. Dikes must be erected and maintained around all crude oil or produced water tanks or above ground equipment, when deemed necessary by the director. Dikes as well as the base material under the dikes and within the diked area must be constructed of sufficiently impermeable material to provide emergency containment. Dikes must be of sufficient dimension to contain the total capacity of the largest tank plus one day's fluid throughput. The required capacity of the dike may be lowered by the director if the necessity therefor can be demonstrated to the director's satisfaction. Discharged crude oil or produced water must be properly removed and may not be allowed to remain standing within or outside of any diked areas.

The underground gathering pipeline owner shall take steps to minimize the amount of solids stored at the pipeline facility, although the remediation of such material may be allowed onsite, if approved by the director.

8.Underground gathering pipeline as built.

The owner of any underground gathering pipeline placed into service after July 31, 2011, shall file with the director, as prescribed by the director, within one hundred eighty days of placing into service, a geographical information system layer utilizing North American datum 83 geographic coordinate system (GCS) and in an environmental systems research institute (Esri) shape file format showing the location of all associated above ground equipment and the pipeline centerline from the point of origin to the termination point. An affidavit of completion shall accompany each layer containing the following information:

a.A third-party inspector certificate that the pipeline was constructed and installed in compliance with section 43-02-03-29.1.

b.The outside diameter, minimum wall thickness, composition, and maximum temperature rating of the pipeline, or any other specifications deemed necessary by the director.

c.The maximum allowable operating pressure of the pipeline.

d.The specified minimum yield strength and internal yield pressure of the pipeline if applicable to the composition of pipe.

e.The type of fluid that will be transported in the pipeline.

f.Pressure and duration to which the pipeline was tested prior to placing into service.

g.The minimum pipeline depth of burial from the top of the pipe to the finished grade.

h.In-service date.

i.Leak protection and monitoring methods that will be utilized after in-service date.

j.Any leak detection methods that have been prepared by the owner.

k.The name of the pipeline gathering system and any other separately named portions thereof.

l.The geographical information system layer must be within twenty feet [6.10 meters] of horizontal accuracy.

9.Operating requirements.

The maximum operating pressure for all crude oil and produced water underground gathering pipelines may not exceed the manufacturer's specifications of the pipe or the manufacturer's specifications of any other component of the pipeline, whichever is less. The maximum operating pressure of any portion of an underground gathering system may not exceed the test pressure from the most recent integrity test demonstration following modification or repair for which it was tested.

The crude oil or produced water underground gathering pipeline must be equipped with adequate controls and protective equipment to prevent the pipeline from operating above the maximum operating pressure.

10.Leak protection, detection, and monitoring.

All crude oil and produced water underground gathering pipeline owners shall file with the director any leak protection and monitoring plan prepared by the owner or required by the director, pursuant to North Dakota Century Code section 38-08-27.

If any leak detection plan has been prepared by the owner, it must be submitted to the All crude oil or produced water underground gathering pipeline owners shall develop and maintain a data sharing plan and file a copy with the director. The plan must provide for realtime sharing of data between the operator of the production facility, the crude oil or produced water underground gathering pipeline owner, and the operator at the point or points of disposal, storage, or sale. If a discrepancy in the shared data is observed, the party observing the data discrepancy shall notify all other parties and action must be taken to determine the cause. A record of all data discrepancies must be retained by the crude oil or produced water underground gathering pipeline owner. If requested, copies of such records must be filed with

11.Spill response.

All crude oil and produced water underground gathering pipeline owners shall maintain a spill response plan during the service life of any crude oil or produced water underground gathering pipeline. The plan should detail the necessary steps for an effective and timely response to a pipeline spill. The spill response plan should be tailored to the specific risks in the localized area. Response capabilities should address access to equipment and tools necessary to respond, as well as action steps to protect the health and property of impacted landowners, citizens, and the environment.

12.Corrosion control.

a.Underground gathering pipelines must be designed to withstand the effects of external corrosion and maintained in a manner that mitigates internal corrosion.

b.All metallic underground gathering pipelines installed must have sufficient corrosion control.

c.All coated pipe must be electronically inspected prior to placement using coating deficiency (i.e. holiday) detectors to check for any faults not observable by visual examination. The holiday detector must be operated in accordance with manufacturer's instructions and at a voltage level appropriate for the electrical characteristics of the pipeline system being tested. During installation all joints, fittings, and tie-ins must be coated with materials compatible with the coatings on the pipe. Coating materials must:

(1)Be designed to mitigate corrosion of the buried pipeline;

(2)Have sufficient adhesion to the metal surface to prevent under film migration of moisture;

(3)Be sufficiently ductile to resist cracking;

(4)Have enough strength to resist damage due to handling and soil stress;

(5)Support any supplemental cathodic protection; and (6)If the coating is an insulating type, have low moisture absorption and provide high electrical resistance.

d.Cathodic protection systems must meet or exceed the minimum criteria set forth in the National Association of Corrosion Engineers standard practice Control of External Corrosion on Underground or Submerged Metallic Piping Systems.

e.If internal corrosion is anticipated or detected, the underground gathering pipeline owner shall take prompt remedial action to correct any deficiencies, such as increased pigging, use of corrosion inhibitors, internal coating of the pipeline (e.g. an epoxy paint or other plastic liner), or a combination of these methods. Corrosion inhibitors must be used in sufficient quantity to protect the entire part of the pipeline system that the inhibitors are designed to protect.

13.Pipeline integrity.

A crude oil or produced water underground gathering pipeline owner may not operate a pipeline unless it has been pressure tested and demonstrated integrity. In addition, an owner may not return to service a portion of pipeline which has been repaired, replaced, relocated, or otherwise changed until it has demonstrated integrity.

a.The crude oil and produced water underground gathering pipeline owner shall notify the director at least forty-eight hours prior to commencement of any pipeline integrity test to allow a representative of the director to witness the testing process and results. The notice must include the pipeline integrity test procedure.

b.The crude oil and produced water underground gathering pipeline owner shall submit within sixty days of the underground gathering pipeline being placed into service the integrity test results which must include the following:

(1)The name of the pipeline gathering system and any other separately named portions thereof;

(2)The date of the test;

(3)The duration of the test;

(4)The length of pipeline which was tested;

(5)The maximum and minimum test pressure;

(6)The starting and ending pressure;

(7)A copy of the appropriately scaled chart recorder or digital log results;

(8)A geographical information system layer utilizing North American datum 83 geographic coordinate system (GCS) and in an environmental systems research institute (Esri) shape file format showing the location of the centerline of the portion of the pipeline that was tested;

(9)A copy of the test procedure used; and (10)A third-party inspector certificate summarizing the pipeline has been pressure tested and whether it demonstrated integrity, including the identification of any leaks, ruptures, or other integrity issues encountered, and an explanation for any substantial pressure gain or losses during the integrity test, if applicable.

c.All crude oil and produced water underground gathering pipeline owners shall maintain a pipeline integrity demonstration plan during the service life of any crude oil or produced water underground gathering pipeline. The director, for good cause, may require a pipeline integrity demonstration on any crude oil or produced water underground gathering pipeline.

14.Pipeline repair.

Each owner, in repairing an underground gathering pipeline or pipeline system, shall ensure that the repairs are made in a manner that prevents damage to persons or property.

An owner may not use any pipe, valve, or fitting, for replacement or repair of an underground gathering pipeline, unless it is designed to meet the maximum operating pressure.

a.At least forty-eight hours prior to any underground gathering pipeline repair or replacement, the underground gathering pipeline owner shall notify the director, except in an emergency.

b.Within one hundred eighty days of repairing or replacing any underground gathering pipeline the owner of the pipeline shall file with the director a geographical information system layer utilizing North American datum 83 geographic coordinate system (GCS) and in an environmental systems research institute (Esri) shape file format showing the location of the centerline of the repaired or replaced pipeline and an affidavit of completion containing the following information:

(1)A statement that the pipeline was repaired in compliance with section (2)The reason for the repair or replacement.

(3)The length of pipeline that was repaired or replaced.

(4)Pressure and duration to which the pipeline was tested prior to returning to service.

c.Clamping or squeezing as a method of repair for any produced water underground gathering pipeline must be approved by the director. Prior to clamping or squeezing the pipeline, the owner shall file a sundry notice (form 4) with the director and obtain approval of the clamping or squeezing plan. The notice must include documentation that the pipeline can be safely clamped or squeezed as prescribed by the manufacturer's specifications. If an emergency requires clamping or squeezing, the owner or the owner's agent shall obtain verbal approval from the director and the notice shall be filed within seven days of completing the repair. Any damaged portion of a produced water underground gathering pipeline that has been clamped or squeezed must be replaced before it is returned to service.

15.Pipeline abandonment.

a.At least forty-eight hours prior to abandoning any underground gathering pipeline, the underground gathering pipeline owner shall notify the director verbally.

b.When an underground gathering pipeline or any part of such pipeline is abandoned as defined under subsection 1 of North Dakota Century Code section 38-08-02 after March 31, 2014, the owner shall leave such pipeline in a safe condition by conducting the (1)Disconnect and physically isolate the pipeline from any operating facility, associated above ground equipment, or other pipeline.

(2)Cut off the pipeline or the part of the pipeline to be abandoned below surface at pipeline level.

(3)Purge the pipeline with fresh water, air, or inert gas in a manner that effectively removes all fluid.

(4)Remove cathodic protection from the pipeline.

(5)Permanently plug or cap all open ends by mechanical means or welded means.

(6)The site of all associated above ground equipment must be reclaimed pursuant to

section 43-02-03-34.1.

(7)If the bury depth is not at least three feet below final grade, such portion of pipe must be removed.

c.Within one hundred eighty days of completing the abandonment of an underground gathering pipeline the owner of the pipeline shall file with the director a geographical information system layer utilizing North American datum 83 geographic coordinate system (GCS) and in an environmental systems research institute (Esri) shape file format showing the location of the pipeline centerline and an affidavit of completion containing the following information:

(1)A statement that the pipeline was abandoned in compliance with section (2)The type of fluid used to purge the pipeline.

(3)The date of pipeline abandonment.

(4)The length of pipeline abandoned.

16.Pipeline markers.

a.Aboveground pipeline markers must be placed and maintained over each buried crude oil or produced water underground gathering pipeline or portion thereof at the discretion of the director when necessary to protect public health and safety. The markers must contain at least the following on a background of sharply contrasting color: the word "Warning", "Caution", or "Danger" followed by the name of the fluid transported pipeline, the name of the operator, and current emergency phone number.

History

• History: Amended effective January 1, 1983; January 1, 2006; April 1, 2014; October 1, 2016; April 1, 2022; April 1, 2024; April 1, 2026.
• Law Implemented: NDCC 38-08-04, 38-08-26 43-02-03-29.1. Crude oil and produced water underground gathering pipelines.
• History: Effective October 1, 2016; amended effective April 1, 2020; April 1, 2022; April 1, 2024.

N.D. Admin. Code 43-02-03-30 Notification of fires, leaks, spills, or blowouts

All persons controlling or operating any well, pipeline and associated aboveground equipment, receiving tank, storage tank, facility, treating plant, or any other receptacle or production facility associated with oil, gas, or water production, injection, processing, or well servicing shall verbally notify the director immediately and follow up utilizing the online initial notification report within twenty-four hours after discovery of any fire, leak, spill, blowout, or release of fluid. The initial report must include the name of the reporting party, including telephone number and address, date and time of the incident, location of the incident, type and cause of the incident, estimated volume of release, containment status, waterways involved, immediate potential threat, and action taken. If any such incident occurs or travels offsite of a facility, the persons, as named above, responsible for proper notification shall within a reasonable time also notify the surface owners upon whose land the incident occurred or traveled.

Notification requirements prescribed by this section do not apply to any leak or spill involving only freshwater or to any leak, spill, or release of crude oil, produced water, or natural gas liquid that is less than one barrel total volume and remains onsite of a site where any well thereon was spud before September 2, 2000, or on a facility that was constructed before September 2, 2000, and do not apply to any leak or spill or release of crude oil, produced water, or natural gas liquid that is less than ten barrels total volume cumulative over a fifteen-day time period, and remains onsite of a site where all wells thereon were spud after September 1, 2000, or on a facility that was constructed after September 1, 2000. The initial notification must be followed by a written report within ten days after cleanup of the incident, unless deemed unnecessary by the director. Such report must include the following information: the operator and description of the facility, the legal description of the location of the incident, date of occurrence, date of cleanup, amount and type of each fluid involved, amount of each fluid recovered, steps taken to remedy the situation, root cause of the incident unless deemed unnecessary by the director, and action taken to prevent reoccurrence, and if applicable, any additional information pursuant to subdivision e of subsection 1 of North Dakota Century Code section 37-17.1-07.1. The name, title, and telephone number of the company representative must be included on such report. The persons, as named above, responsible for proper notification shall within a reasonable time also provide a copy of the written report to the surface owners upon whose land the incident occurred or traveled.

The commission, however, may impose more stringent spill reporting requirements if warranted by proximity to sensitive areas, past spill performance, or careless operating practices as determined by

At no time shall any spill or leak be allowed to flow over, pool, or rest on the surface of the land or infiltrate the soil. Discharged fluids must be properly removed and may not be allowed to remain standing within or outside of diked areas, although the remediation of such fluids may be allowed onsite if approved by the director. Operators and responsible parties must respond with appropriate resources to contain and clean up spills.

A sundry notice (form 4) must be submitted within ten days after cleanup of any spill or leak in which fluids are not properly removed or appropriate resources are not utilized to contain and clean up the spill unless deemed unnecessary by the director. The notice must include the date of the occurrence, date of cleanup, amount and type of each fluid involved, identification of the site affected, root cause of the incident, and explanation of how the volume was determined.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; July 1, 1996; January 1, 2008; April 1, 2010; April 1, 2014; October 1, 2016; April 1, 2018; April 1, 2020; April 1, 2022. 43-02-03-30.1. Leak and spill cleanup.
• History: Effective April 1, 2012; amended effective October 1, 2016; April 1, 2018.

N.D. Admin. Code 43-02-03-31 Well log, completion, and workover reports

1.After the plugging of a well, a well plugging report must be filed with the director. After the completion of a well, recompletion of a well in a different pool, or drilling horizontally in an existing pool, a well completion report must be filed with the director. The operator shall cause to be run an open hole electrical, radioactivity, or other similar log, or combination of open hole logs, of the operator's choice, from which formation tops and porosity zones can be determined. The operator shall cause to be run a gamma ray log from total depth to ground level elevation of the well bore. Within six months of reaching total depth and prior to completing the well, the operator shall cause to be run a cement evaluation log from which the presence and quality of bonding of cement can be determined in every well in which production or intermediate casing has been set. The initial cement evaluation log must be run without the addition of pressure at surface, except at depths where the cement evaluation tool may need appropriate pressure applied to function properly. The obligation to log may be waived or postponed by the director if the necessity therefor can be demonstrated to the director's satisfaction. Waiver will be contingent upon such terms and conditions as the director deems appropriate. All logs run must be available to the director at the well site prior to proceeding with plugging or completion operations. All logs run shall be submitted to the director free of charge. Logs must be submitted as one digital TIFF (tagged image file format) copy and one digital LAS (log ASCII) formatted copy, or a format approved by the director. In addition, operators shall file one copy of drill stem test reports and charts, formation water analyses, core analyses, geologic reports, and noninterpretive lithologic logs or sample descriptions if compiled by the operator.

2.All information furnished to the director on permits, except the operator name, well name, location, permit date, confidentiality period, spacing or drilling unit description, spud date, rig contractor, central tank battery number, any production runs, or volumes injected into an injection well, must be kept confidential from the date a request by the operator is received in writing until the six-month confidentiality period has ended. The six-month period commences on the date the well is completed or the date the written request is received, whichever is earlier. If the written request accompanies the application for permit to drill or is filed after permitting but prior to spudding, the six-month period commences on the date the well is spudded. The director may release such confidential completion and production data to health care professionals, emergency responders, and state, federal, or tribal environmental and public health regulators if the director deems it necessary to protect the public's health, safety, and welfare.

3.All information furnished to the director on recompletions, restimulation wells, or reentries, except the operator name, well name, location, permit date, confidentiality period, spacing or drilling unit description, spud date, rig contractor, any production runs, or volumes injected into an injection well, must be kept confidential for not more than six months if requested by the operator in writing. The six-month period commences on the date the well is completed, recompleted, or restimulated or the date a request by the operator is received in writing, whichever is earlier. Any information furnished to the director prior to approval of the recompletion, restimulation, or reentry must remain public.

4.Approval must be obtained on a well sundry notice from the director prior to perforating or recompleting a well in a pool other than the pool in which the well is currently permitted.

5.After the completion of any remedial work, or attempted remedial work such as plugging back or drilling deeper, acidizing, shooting, formation fracturing, squeezing operations, remedial cementing, setting liner, perforating, reperforating, or other similar operations not specifically covered herein, a report on the operation shall be filed on a well sundry notice with the director. The report must present a detailed account of all work done and the date of such work; the shots per foot, size, and depth of perforations; the quantity of cement, sand, crude, chemical, or other materials employed in the operation; any other pertinent information or operations which affect the original status of the well and are not specifically covered herein, and any other information required by the director.

6.Upon the installation of pumping equipment on a flowing well, or change in type of pumping equipment designed to increase productivity in a well, the operator shall submit a well sundry notice of such installation. The notice must include all pertinent information on the pump and the operation thereof including the date of such installation.

7.All forms, reports, logs, and other information required by this section must be submitted within thirty days after the completion of such work, although a completion report must be filed immediately after the completion or recompletion of a well in a pool or reservoir not then covered by an order of the commission.

July 1, 1996; September 1, 2000; July 1, 2002; January 1, 2006; January 1, 2008; April 1, 2010; April 1, 2012; October 1, 2016; April 1, 2020; April 1, 2024; April 1, 2026.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1990; May 1, 1992; May 1, 1994;

N.D. Admin. Code 43-02-03-32 Stratigraphic test and core holes

Stratigraphic test and core holes shall be permitted the same as oil and gas wells, although no setback from a drilling unit shall be required.

History

• History: Amended effective April 30, 1981; January 1, 1983; July 1, 2002.

N.D. Admin. Code 43-02-03-33 Notice of intention to plug well

The operator or the operator's agent shall file a notice of intention (form 4) to plug with the director, and obtain the approval of the director, prior to the commencement of plugging or plug-back operations.

The notice shall state the name and location of the well, the name of the operator, and the method of plugging, which must include a detailed statement of proposed work, and a well bore diagram showing the current conditions downhole, including all data pertinent to plugging the well in an effective manner.

In the case of a recently completed test well that has not had production casing in the hole, the operator may commence plugging by giving reasonable notice to, and securing verbal approval of, the director as to the method of plugging, and the time plugging operations are to begin. Within thirty days after the plugging of any well has been accomplished, the owner or operator thereof shall file a plugging record (form 7), and, if requested, a copy of the cementer's trip ticket or job receipt, with the director setting forth in detail the method used in plugging the well.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; January 1, 2006; April 1, 2018.

N.D. Admin. Code 43-02-03-34 Method of plugging

All wells shall be plugged in a manner which will confine permanently all oil, gas, and water in the separate strata originally containing them. This operation shall be accomplished by the use of mud-laden fluid, cement, and plugs, used singly or in combination as may be approved by the director.

All casing strings shall be cut off at least three feet [91.44 centimeters] below the final surface contour, and a cap with file number shall be welded thereon. Core or stratigraphic test holes drilled to or below sands containing freshwater shall be plugged in accordance with the applicable provisions recited above. After plugging, the site must be reclaimed pursuant to section 43-02-03-34.1.

April 1, 2014; October 1, 2016. 43-02-03-34.1. Reclamation of surface.

1.Within a reasonable time, but not more than one year, after a well is plugged, or if a permit expires, has been canceled or revoked, or a treating plant or saltwater handling facility is decommissioned, the site, access road, and other associated facilities constructed must be reclaimed as closely as practicable to original condition pursuant to North Dakota Century Code section 38-08-04.12. Prior to site reclamation, the operator or the operator's agent shall file a well sundry form or facility sundry notice with the director and obtain approval of a reclamation plan. The operator or operator's agent shall provide a copy of the proposed reclamation plan to the surface owner at least ten days prior to commencing the work unless waived by the surface owner. Verbal approval to reclaim the site may be given. The notice must include:

a.The name and address of the reclamation contractor;

b.The name and address of the surface owner and the date when a copy of the proposed reclamation plan was provided to the surface owner;

c.A description of the proposed work, including topsoil redistribution and reclamation plans for the access road and other associated facilities; and

d.Reseeding plans, if applicable.

The commission will mail a copy of the approved notice to the surface owner.

All equipment, waste, and debris shall be removed from the site. All pipelines shall be purged and abandoned pursuant to section 43-02-03-29.1. Flow lines shall be removed if buried less than three feet [91.44 centimeters] below final contour.

2.Gravel or other surfacing material must be removed, stabilized soil shall be remediated, and the site, access road, and other associated facilities constructed for the well, treating plant, or saltwater handling facility shall be reshaped as near as practicable to original contour.

3.The stockpiled topsoil must be distributed evenly over the disturbed area and, where applicable, the area revegetated with native species or according to the reasonable specifications of the appropriate government land manager or surface owner.

4.A site assessment may be required by the director, before and after reclamation of the site.

5.Within thirty days after completing any reclamation, the operator shall file a sundry notice with the director reporting the work performed.

6.The director, with the consent of the appropriate government land manager or surface owner, may waive the requirement of reclamation of the site and access road after a well is plugged or treating plant or saltwater handling facility is decommissioned. The director shall record documentation of the waiver with the recorder of the county in which the site or road is located.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1990; May 1, 1992; July 1, 2002;
• History: Effective April 1, 2012; amended effective April 1, 2014; October 1, 2016; April 1, 2018; April 1, 2020; April 1, 2022; April 1, 2024.

N.D. Admin. Code 43-02-03-35 Conversion of mineral wells to freshwater wells

Any person desiring to convert a mineral well to a freshwater well, as provided by North Dakota Century Code section 61-01-27, shall file an application for approval with the commission. The application must include, but is not limited to, the following:

1.If the well is to be used for other than individual domestic and livestock use, a conditional water permit issued by the department of water resources.

2.An affidavit by the person desiring to obtain approval for the conversion stating that such person has the authority and assumes all liability for the use and plugging of the proposed freshwater well.

3.The procedure which will be followed in converting the mineral well to a freshwater well.

4.If the well is not currently plugged and abandoned, an affidavit must be executed by the operator of the well indicating that the parties responsible for plugging the mineral well have no objection to the conversion of the mineral well to a freshwater well.

If the commission, after notice and hearing, determines that a mineral well may safely be used as a freshwater well, the commission may approve the conversion.

History

• History: Amended effective April 30, 1981; January 1, 1983; September 1, 1987; July 1, 2002; April 1,

N.D. Admin. Code 43-02-03-36 Liability

The owner and operator of any well, core hole, or stratigraphic test hole, whether cased or uncased, shall be liable and responsible for the plugging and site reclamation thereof in accordance with the rules and regulations of the commission.

History

• History: Amended effective January 1, 1983; May 1, 1994.

N.D. Admin. Code 43-02-03-37 Slush pits

N.D. Admin. Code 43-02-03-38 Preservation of cores and samples. 43-02-03-38.1. Preservation of cores and samples

Unless waived by the director, operators shall have a well site geologist or mudlogger on location for at least the first well drilled on a multiwell pad to collect sample cuttings and to create a mudlog and geologic report. Sample cuttings of formations, taken at intervals prescribed by the state geologist, in all wells drilled for the production of oil or gas, injection, disposal, storage operations, or geological information in North Dakota, shall be washed and packaged in standard sample envelopes which in turn shall be placed in proper order in a standard sample box; carefully identified as to operator, well name, well file number, American petroleum institute number, location, depth of sample; and shall be sent free of cost to the state core and sample library within thirty days after completion of drilling operations.

The operator of any well drilled for the production of oil or gas, injection, disposal, storage operations, or geological information in North Dakota, during the drilling of or immediately following the completion of any well, shall inform the director of all intervals that are to be cored, or have been cored.

Unless specifically exempted by the director, all cores taken shall be preserved, placed in a standard core box and the entire core forwarded to the state core and sample library, free of cost, within one hundred eighty days after completion of drilling operations. The director may grant an extension of the one hundred eighty-day time period for good reason. If an exemption is granted, the operator shall advise the state geologist of the final disposition of the core.

This section does not prohibit the operator from taking such samples of the core as the operator may desire for identification and testing. The operator shall furnish the state geologist with the results of all identification and testing procedures within thirty days of the completion of such work. The state geologist may grant an extension of the thirty-day time period for good reason.

The size of the standard envelopes, sample boxes, and core boxes shall be determined by the director and indicated in the cores and samples letter.

April 1, 2022.

History

• History: Effective October 1, 1990; amended effective January 1, 2006; April 1, 2014; April 1, 2020;

N.D. Admin. Code 43-02-03-39 Limiting gas-oil ratio

In the event the commission has not set a limiting gas-oil ratio for a particular pool, the operator of any well in such pool whose gas-oil ratio exceeds two thousand shall demonstrate to the director that production from such well should not be restricted pending a hearing before the commission to establish a limiting gas-oil ratio. The director may restrict production of any well with a gas-oil ratio exceeding two thousand, until the commission can determine that restrictions are necessary to conserve reservoir energy.

In the event the commission has not established spacing and special field rules for a particular oil pool, oil production from any well completed therein shall be a maximum of two thousand barrels per day until the commission issues a decision after hearing. The director shall have the authority to waive production limitations for good cause, and for special tests.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; January 1, 2006. 43-02-03-39.1. Oil production limitation.
• History: Effective July 1, 1996.

N.D. Admin. Code 43-02-03-40 Gas-oil ratio test

Each operator shall take a gas-oil ratio test within thirty days following the completion or recompletion of an oil well. Each test shall be conducted using standard industry practices unless otherwise specified by the director. The initial gas-oil ratio must be reported on the well completion or recompletion report (form 6 or form provided by the commission). Subsequent gas-oil ratio tests must be performed on producing wells when the producing pool appears to have reached bubble point. After the discovery of a new pool, each operator shall make additional gas-oil ratio tests as directed by the director or provided for in field rules. During tests each well shall be produced at a maximum efficient rate. The director may shut in any well for failure to make such test until such time as a satisfactory test can be made, or satisfactory explanation given. The results of all gas-oil ratio tests shall be submitted to the director on form 9, which shall be accompanied by a statement that the data on form 9 is true and correct.

October 1, 2016; April 1, 2020.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; September 1, 2000;

N.D. Admin. Code 43-02-03-41 Subsurface pressure tests

The operator shall make a subsurface pressure test on the discovery well of any new pool hereafter discovered and shall report the results thereof to the director within thirty days after the completion of such discovery well. Drill stem test pressures are acceptable. After the discovery of a new pool, each operator shall make additional subsurface pressure tests as directed by the director or provided for in field rules. All tests shall be made by a person qualified by both training and experience to make such tests and with an approved subsurface pressure instrument. All wells must remain completely shut in for at least forty-eight hours prior to the test. The subsurface determination must be obtained as close as possible to the top of the formation containing the productive interval of the reservoir. The report of the reservoir pressure test shall be filed on form 9a.

The director may shut in any well for failure to make such test as herein above described until such time as a satisfactory test has been made or satisfactory explanation given.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; September 1, 2000; April 1,

N.D. Admin. Code 43-02-03-42 Commingling of oil from pools

Except as directed by the commission after hearing, each pool shall be produced as a single common reservoir without commingling in the well bore of fluids from different pools. After fluids from different pools have been brought to surface, such fluids may be commingled provided that the amount of production from each pool is determined by a method approved by the director.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992.

N.D. Admin. Code 43-02-03-43 Control of multiply completed wells

N.D. Admin. Code 43-02-03-44 Vented, flared, and metered casinghead gas

1.Pending arrangements for disposition for some useful purpose, all vented casinghead gas must be burned. Each flare must be equipped with an automatic ignitor or a continuous burning pilot, unless waived by the director for good reason.

2.All casinghead gas produced must be reported monthly to the director in units of one thousand cubic feet [28.32 cubic meters] computed at a pressure of fourteen and seventy-three hundredths pounds per square inch absolute [1034.19 grams per square centimeter] at a base temperature of sixty degrees Fahrenheit [15.56 degrees Celsius].

Associated gas production may not be transported from a well premises or central production facility until its volume has been determined through the use of properly calibrated measurement equipment. All measurement equipment and volume determinations must conform to American gas association standards. The operator of a well shall notify the director within thirty days on a well sundry notice of the connection date to a gas gathering system, the metering equipment, transporter, and purchaser of the gas. Any gas produced and used on lease for fuel purposes or flared may be estimated or measured and must be reported on a gas report in accordance with section 43-02-03-52.1. Meters used to determine the use on lease or flared gas volumes must be installed and calibrated in accordance with American petroleum institute or American gas association standards or to the meter manufacturer's recommendations.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; July 1, 1996; September 1, 2000; April 1, 2024; April 1, 2026.

N.D. Admin. Code 43-02-03-45 Vented casinghead gas

Repealed effective April 1, 2026.

N.D. Admin. Code 43-02-03-46 Use of vacuum pumps

N.D. Admin. Code 43-02-03-47 Produced water

Monthly water production from each well must be determined through the use of properly calibrated meter measurements, tank measurements, or an alternate measurement method approved by the director. This includes allocating water production back to individual wells on a monthly basis, provided the method of volume determination and allocation procedure results in reasonably accurate production volumes. Operators shall report monthly to the director the amount of water produced by each well on an oil report. The reports must be filed by five p.m on the first day of the second month following that in which production occurred.

History

• History: Amended effective January 1, 1983; May 1, 1992; May 1, 1994; September 1, 2000; April 1, 2026.

N.D. Admin. Code 43-02-03-48 Measurement of oil

Oil production may not be transported from a well premises, central production facility, treating plant, or saltwater handling facility until its volume has been determined through the use of properly calibrated meter measurements or tank measurements. All meter and tank measurements, and volume determinations must conform to American petroleum institute standards and be corrected to a base temperature of sixty degrees Fahrenheit [15.56 degrees Celsius] and fourteen and seventy-three hundredths pounds per square inch absolute [1034.19 grams per square centimeter].

July 1, 1996; April 1, 2014; October 1, 2016. 43-02-03-48.1. Central production facility - Commingling of production.

1.The director may approve requests to consolidate production equipment at a central location.

The applicant shall provide all information requested by the director. The director may impose such terms and conditions as the director deems necessary.

2.Commingling of oil and gas production from two or more wells in a central production facility is prohibited unless approved by the director. There are two types of central production facilities in which production from two or more wells is commingled that may be approved by the director :

a.A central production facility in which all production going into the facility has common ownership. For purposes of this section, production with common ownership is defined as production from wells that do not have diverse ownership.

b.A central production facility in which production going into the facility has diverse ownership. For purposes of this section, production with diverse ownership is defined as production from wells:

(1)That are in different drilling or spacing units; and (2)Which have different mineral ownership.

3.The commingling of oil and gas production in a central production facility from two or more wells having common ownership may be approved by the director provided the production from each well can be accurately determined at reasonable intervals. Commingling of oil and gas production in a central production facility from two or more wells having diverse ownership may be approved by the director provided the production from each well is accurately metered prior to commingling. Commingling of oil and gas production in a central production facility from two or more wells having diverse ownership which is not metered prior to commingling may only be approved by the commission after notice and hearing.

a.The application for permission to commingle oil, gas, or both in a central production facility with common ownership must be submitted on a facility sundry notice and must (1)A plat or map showing thereon the location of the central facility and the name, well file number, and location of each well and flow lines from each well that will produce into the facility.

(2)A schematic drawing of the facility which diagrams the testing, treating, routing, and transferring of production. All pertinent items such as treaters, tanks, flow lines, valves, meters, recycle pumps, etc., must be shown.

(3)An affidavit executed by a person who has knowledge indicating that common ownership as defined above exists.

(4)The name of the manufacturer, size, and type of allocation meters to be used. Oil meters must be proved at least semiannually and gas meters must be calibrated at least annually. The results must be reported to the director within thirty days following the completion of the test.

(5)An explanation of the procedures or method to be used to determine, accurately, individual well production at periodic intervals. Such procedures or method must be performed at least quarterly.

A copy of all tests are to be filed with the director on a central tank battery well test form within thirty days after the tests are completed.

b.The application for permission to commingle oil, gas, or both in a central production facility having diverse ownership must be submitted on a facility sundry notice and shall (1)A plat or map showing thereon the location of the central facility and the name, well file number, and location of each well, and flow lines from each well that will produce into the facility.

(2)A schematic drawing of the facility which diagrams the testing, treating, routing, and transferring of production. All pertinent items such as treaters, tanks, flow lines, valves, meters, recycle pumps, etc., must be shown.

(3)The name of the manufacturer, size, and type of allocation meters to be used. Oil meters must be proved at least once every three months and gas meters must be calibrated at least semiannually. The results must be reported to the director within thirty days following the completion of the test.

(4)An explanation of the procedures or method to be used to accurately determine individual well production at periodic intervals. Such procedures or method must be performed at least monthly.

A copy of all tests must be filed with the director on a central tank battery well test form within thirty days after the tests are completed.

4.The commingling of produced water in a central production facility from two or more wells may be approved by the director provided the produced water production can be accurately determined at reasonable intervals. The application for permission to commingle water in a central production facility must be submitted on a facility sundry notice and must include the

a.A plat or map showing thereon the location of the central facility and the name, well file number, and location of each well, and flow lines from each well that will produce into the facility.

b.A schematic drawing of the facility which diagrams the testing, treating, routing, and transferring of production. All pertinent items such as treaters, tanks, flow lines, valves, meters, recycle pumps, etc., must be shown.

c.An affidavit executed by a person who has knowledge indicating that common ownership as defined above exists; or an indication that it is not common ownership.

d.The name of the manufacturer, size, and type of allocation meters to be used. Allocation meters must be installed and calibrated in accordance with American petroleum institute or to the meter manufacturer's recommendations.

e.An explanation of the procedures or method to be used to determine, accurately, individual well production at periodic intervals. Such procedures or method must be performed quarterly for common ownership and central production facilities monthly for diverse ownership central production facilities.

5.Any changes to a previously approved central production facility must be reported on a facility sundry notice and approved by the director.

6.After notice and hearing pursuant to sections 43-02-03-88.2 through 43-02-03-101, the commission may revoke the authorization to commingle production in a central production facility for failure to comply with this section or any terms, conditions, or directives imposed by

History

• History: Amended effective April 30, 1981; March 1, 1982; January 1, 1983; May 1, 1992; May 1, 1994;
• History: Effective May 1, 1992; amended effective September 1, 2000; May 1, 2004; April 1, 2020, April 1, 2024; April 1, 2026.

N.D. Admin. Code 43-02-03-49 Oil production equipment, dikes, and seals

1.Storage of oil in underground or partially buried tanks or containers is prohibited. Surface oil tanks and production equipment must be devoid of leaks and constructed of materials resistant to the effects of produced fluids or chemicals that may be contained therein. Unused tanks and production equipment must be removed from the site or placed into service, within a reasonable time period, not to exceed one year.

2.Dikes must be erected around oil tanks, flowthrough process vessels, and recycle pumps at any new production facility prior to completing any well. The dikes must be erected and maintained around oil tanks at all facilities unless a waiver is granted by the director. Dikes as well as the base material under the dikes and within the diked area must be constructed of sufficiently impermeable material to provide emergency containment. Dikes around oil tanks must be of sufficient dimension to contain the total capacity of the largest tank plus one day's fluid production. Dikes around flowthrough process vessels must be of sufficient dimension to contain the total capacity of the vessel. The required capacity of the dike may be lowered by the director if the necessity therefor can be demonstrated to the director's satisfaction.

3.Within one hundred eighty days from the date the operator is notified by the commission, a perimeter berm, at least six inches [15.24 centimeters] in height, must be constructed and maintained. The berm must be constructed of sufficiently impermeable material to provide emergency containment and to divert surface drainage away from the site around all storage facilities and production sites that include storage tanks, have a daily throughput of more than one hundred barrels of fluid per day, and include production equipment or load lines that are not contained within secondary containment dikes. The director may consider an extension of time to implement these requirements if conditions prevent timely construction, or a modification of these requirements if other factors are present that provide sufficient protection from environmental impacts. Prior to removing any perimeter berm, the operator or owner shall obtain approval by the director.

4.Numbered weather-resistant security seals must be properly utilized on all oil access valves and access points to secure the tank or battery of tanks.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; September 1, 2000; July 1, 2002; May 1, 2004; April 1, 2010; April 1, 2012; October 1, 2016; April 1, 2018; April 1, 2020; April 1, 2026.

N.D. Admin. Code 43-02-03-50 Tank cleaning permit

No tank bottom waste shall be removed from any tank used for the storage or sale of crude oil without prior approval by the director. Verbal approval may be given. Prior approval to remove tank bottom waste from tanks not used for the storage or sale of crude oil is not required.

Within thirty days of the removal of the tank bottom waste of any tank used for the storage or sale of crude oil, the owner or operator shall submit a report (form 23) showing an accurate gauge of the contents of the tank and the amount of merchantable oil determinable from a representative sample of the tank bottom by the standard centrifugal test as prescribed by the American petroleum institute's code for measuring, sampling, and testing crude oil.

Within thirty days of the removal of the tank bottom waste of any permanent tank not used for the storage or sale of crude oil, the owner or operator shall submit a sundry notice (form 4) detailing the cleaning operation.

All tank bottom waste must be disposed of in a manner authorized by the director and in accordance with all applicable local, state, and federal laws and regulations. Nothing contained in this

section shall apply to reclaiming of pipeline break oil or the treating of tank bottoms at a pipeline station, crude oil storage terminal, or refinery or to the treating by a gasoline plant operator of oil and other catchings collected in traps and drips in the gas gathering lines connected to gasoline plants and in scrubbers at such plants.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; May 1, 1994; September 1, 2000; May 1, 2004.

N.D. Admin. Code 43-02-03-51 Treating plant

No treating plant may be constructed or site or access road construction commenced without obtaining a permit from the commission after notice and hearing. A written application for a treating plant permit shall state in detail the location, type, capacity of the plant contemplated, method of processing proposed, and the plan of operation for all plant waste. The director shall give the county auditor notice at least fifteen days prior to the hearing of any application in which a request for a treating plant is received.

1.The treating plant permit application must be submitted on form 1tp and shall include at least the following information:

a.The name and address of the operator.

b.An accurate plat certified by a registered surveyor showing the location of the proposed treating plant and the center of the site with reference to true north and the nearest lines of a governmental section. The plat shall also include the latitude and longitude of the center of the proposed treating plant location to the nearest tenth of a second, and the ground elevation. The plat shall also depict the outside perimeter of the treating plant and verification that the site is at least five hundred feet [152.4 meters] from an occupied dwelling.

c.A schematic drawing of the proposed treating plant site, drawn to scale, detailing all facilities and equipment, including the size, location, and purpose of all tanks, the height and location of all dikes, the location of all flow lines, and the location of the topsoil stockpile. It shall also include the proposed road access to the nearest existing public road and the authority to build such access.

d.Cut and fill diagrams.

e.An affidavit of mailing identifying each owner of any permanently occupied dwelling within one-quarter mile of the proposed treating plant and certifying that such owner has been notified of the proposed treating plant.

f.Appropriate geological data on the surface geology and its suitability for fluid containment.

g.Schematic drawings of the proposed diking and containment, including calculated containment volume and all areas underlain by a synthetic liner.

h.Monitoring plans and leak detection for all buried or partially buried structures and any concrete structure upon which waste or product is in direct contact.

i.The capacity and operational capacity of the treating plant.

j.A narrative description of the process and how the waste and recovered product streams travel through the treating plant.

k.A review of the surficial aquifers within one mile of the proposed treating plant site or surface facilities.

l.Any other information required by the director to evaluate the proposed treating plant or site.

2.Permits may contain such terms and conditions as the director deems necessary.

3.Any permit issued under this section may be revoked by the commission after notice and hearing if the permittee fails to comply with the terms and conditions of the permit, any directive of the director, or any applicable rule or statute. Any permit issued under this section may be suspended by the director for good cause.

4.Permits are transferable only with approval of the director.

5.Permits may be modified by the director.

6.A permit must automatically expire one year after the date it was issued, unless dirtwork operations have commenced to construct the site. The director may extend a treating plant permit for up to one year upon request.

7.If the treating plant is abandoned and reclaimed, the permit must expire and be of no further force and effect.

All treating plants shall be sited in such a fashion that they are not located in a geologically or hydrologically sensitive area.

1.Before construction of a treating plant, treating plant site, or access road begins, the operator shall file with the director a surety bond or cash bond conditioned upon compliance with all laws, rules and regulations, and orders of the commission. The bond amount must be specified in the commission order authorizing the treating plant and shall be based upon the location, type, and capacity of the plant, processing method, and plan of operation for all plant waste approved in the commission order and shall be payable to the industrial commission. In no case may the bond amount be set lower than fifty thousand dollars.

2.Treating plant sites and associated facilities or appropriate parts thereof must be fenced if required by the director. All fences installed within or around any facility must be constructed in a manner that promotes emergency ingress and egress.

3.All storage tanks must be kept free of leaks and in good condition. Storage tanks for saltwater must be constructed of, or lined with, materials resistant to the effects of saltwater. Open tanks are allowed if approved by the director.

4.All waste, recovered solids, and recovered fluids must be stored and handled in such a manner to prevent runoff or migration offsite.

5.Dikes of sufficient dimension to contain the total capacity of the maximum volume stored must be erected and maintained around all storage and processing tanks. Dikes as well as the base within the diked area must be lined with a synthetic impermeable liner to provide emergency containment unless waived by the director. All processing equipment shall be underlain by a synthetic impermeable material, unless waived by the director. The site must be sloped and diked to divert surface drainage away from the site. The operations of the treating plant shall be conducted in such a manner as to prevent leaks, spills, and fires. All discharged fluids and wastes shall be promptly and properly removed and shall not be allowed to remain standing within the diked area or on the treating plant premises. All such incidents must be properly cleaned up, subject to approval by the director. All such reportable incidents must be promptly reported to the director and a detailed account of any such incident must be filed with the director in accordance with section 43-02-03-30.

6.A perimeter berm, at least six inches [15.24 centimeters] in height, must be constructed of sufficiently impermeable material to provide emergency containment around the treating plant and to divert surface drainage away from the site if deemed necessary by the director.

7.Within thirty days following construction or modification of a treating plant, a sundry notice (form 4) must be submitted detailing the work and the dates commenced and completed. The sundry notice must be accompanied by a schematic drawing of the treating plant site drawn to scale, detailing all facilities and equipment, including the size, location, and purpose of all tanks; the height and location of all dikes as well as a calculated containment volume; all areas underlain by a synthetic liner; any leak detection system installed; the location of all flowlines; the stockpiled topsoil location and its volume; and the road access to the nearest existing public road.

8.Immediately upon the commencement of treatment operations, the operator shall notify the director in writing of such date.

9.The operator of a treating plant shall provide continuing surveillance and conduct such monitoring and sampling as the director may require.

10.Storage pits, waste pits, or other earthen storage areas must be prohibited unless authorized by an appropriate regulatory agency. A copy of said authorization must be filed with the

11.Burial of waste at any treating plant site shall be prohibited. All residual water and waste, fluid or solid, must be disposed of in an authorized facility.

12.The operator shall take steps to minimize the amount of residual waste generated and the amount of residual waste temporarily stored onsite. Solid waste shall not be stockpiled onsite unless authorized by an appropriate regulatory agency. A copy of said authorization shall be filed with the director.

13.If deemed necessary by the director, the operator shall cause to be analyzed any waste substance contained onsite. Such chemical analysis shall be performed by a certified laboratory and shall adequately determine if chemical constituents exist which would categorize the waste as hazardous by department of environmental quality standards.

14.Treating plants must be constructed and operated so as not to endanger surface or subsurface water supplies or cause degradation to surrounding lands and shall comply with

section 43-02-03-28 concerning fire hazards and proximity to occupied dwellings.

15.The beginning of month inventory, the amount of waste received and the source of such waste, the volume of oil sold, the amount and disposition of water, the amount and disposition of residue waste, fluid or solid, and the end of month inventory for each treating plant shall be reported monthly on form 5p with the director on or before the first day of the second succeeding month, regardless of the status of operations.

16.Records necessary to validate information submitted on form 5p must be maintained in North Dakota.

17.All proposed changes to any treating plant must have prior approval by the director.

18.The operator shall comply with all applicable rules and orders of the commission. All rules in this chapter governing oil well sites shall also apply to any treating plant site.

19.The operator shall immediately cease operations if so ordered by the director for failure to comply with the statutes of North Dakota, commission rules or orders, or directives of the

Notice of intention to abandon. The operator or the operator's agent shall file a notice of intention (form 4) to abandon and obtain the approval of the director, prior to the commencement of reclamation operations pursuant to section 43-02-03-34.1.

History

• History: Amended effective January 1, 1983; May 1, 1990; May 1, 1992; September 1, 2000; April 1, 2012; April 1, 2014; April 1, 2020. 43-02-03-51.1. Treating plant permit requirements.
• History: Effective April 1, 2014; amended effective October 1, 2016; April 1, 2020; April 1, 2024. 43-02-03-51.2. Treating plant siting.
• History: Effective April 1, 2014. 43-02-03-51.3. Treating plant construction and operation requirements.
• History: Effective April 1, 2014; amended effective October 1, 2016; April 1, 2018; April 1, 2020; April 1, 43-02-03-51.4. Treating plant abandonment and reclamation requirements.
• History: Effective April 1, 2014; amended effective April 1, 2018.

N.D. Admin. Code 43-02-03-52 Report of oil production

The operator of each well completed in any pool shall, by five p.m. on the first day of the second month succeeding the month in which production occurs or could occur, file with the director the amount of production made by each such well on an oil report. Wells for which reports of production are not received by five p.m. on said first day of the month may be shut in for a period not to exceed thirty days. The director shall notify, by certified mail, the operator and authorized transporter of the shut-in period for the wells. Any oil produced during the shut-in period shall be deemed illegal oil and subject to the provisions of North Dakota Century Code section 38-08-15.

September 1, 2000; October 1, 2016; April 1, 2026. 43-02-03-52.1. Report of gas produced in association with oil.

The operator of each well completed in any pool shall, by five p.m. on the fifth day of the second month succeeding the month in which production occurs or could occur, file with the director the amount of gas produced by each such well on a gas report. Wells for which reports of production are not received by five p.m. on said fifth day of the month may be shut in for a period not to exceed thirty days. The director shall notify by certified mail the operator and authorized transporter of the shut-in period for the wells. Any gas produced during the shut-in period must be deemed illegal gas and subject to the provisions of North Dakota Century Code section 38-08-15.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; December 1, 1997;
• History: Effective May 1, 1992; amended effective December 1, 1997; September 1, 2000; October 1, 2016; April 1, 2026.

N.D. Admin. Code 43-02-03-53 Saltwater handling facilities

1.A saltwater handling facility may not be constructed without obtaining a permit from the director. Saltwater handling facilities in existence prior to October 1, 2016, which are not currently bonded as an appurtenance to a well or treating plant, have ninety days from the date notified by the director that a permit is required to submit the required information in order for the director to approve such facility.

2.All saltwater liquids or brines produced with oil and natural gas shall be processed, stored, and disposed of without pollution of freshwater supplies.

3.Underground injection of saltwater liquids and brines shall be in accordance with chapter 43-02-05.

4.The permitting and bonding requirements for a saltwater handling facility set forth in sections 43-02-03-53, 43-02-03-53.1, and 43-02-03-53.3 are not to be construed to be required if the facility is bonded as a well or treating plant appurtenance. Such facilities will be considered in the permit application for the well or treating plant.

1.A permit for construction of a saltwater handling facility, saltwater handling facility site, or access road must be approved by the director prior to construction. The saltwater handling facility permit application must be submitted on a facility sundry notice and include at least the following information:

a.The name and address of the operator.

b.An accurate plat certified by a registered surveyor showing the location of the proposed saltwater handling facility and the center of the site with reference to true north and the nearest lines of a governmental section. The plat also must include the latitude and longitude of the center of the proposed saltwater handling facility location to the nearest tenth of a second and the ground elevation. The plat also must depict the outside perimeter of the saltwater handling facility and verification that the site is at least five hundred feet [152.4 meters] from an occupied dwelling.

c.A schematic drawing of the proposed saltwater handling facility site, drawn to scale, detailing all facilities and equipment, including the size, location, and purpose of all tanks, the height and location of all dikes, the location of all flow lines, and the location and thickness of the stockpiled topsoil. The schematic drawing also must include the proposed road access to the nearest existing public road and the authority to build such access.

d.Cut and fill diagrams.

e.Schematic drawings of the proposed diking and containment, including calculated containment volume and all areas underlain by a synthetic liner, as well as a description of all containment construction material.

f.The anticipated daily throughput of the saltwater handling facility.

g.A review of the surficial aquifers within one mile of the proposed treating plant site or surface facilities.

h.Any other information required by the director to evaluate the proposed saltwater handling facility or site.

2.Permits may contain such terms and conditions as the director deems necessary.

3.Any permit issued under this section may be revoked by the commission after notice and hearing if the permittee fails to comply with the terms and conditions of the permit, any directive of the director, or any applicable rule or statute. Any permit issued under this section may be suspended by the director for good cause.

4.Permits are transferable only with approval of the director.

5.Permits may be modified by the director.

6.A permit automatically expires one year after the date it was issued, unless dirtwork operations have commenced to construct the site. The director may extend a saltwater handling facility permit for up to one year upon request.

7.If the saltwater handling facility is abandoned and reclaimed, the permit expires and is of no further force and effect.

All saltwater handling facilities must be sited in such a fashion that they are not located in a geologically or hydrologically sensitive area.

1.Before construction of a saltwater handling facility, saltwater handling facility site, or access road begins, the operator shall file with the director a surety bond or cash bond conditioned upon compliance with all laws, rules and regulations, and orders of the commission. The bond must be in the amount of fifty thousand dollars and must be payable to the industrial commission. The commission, after notice and hearing, may require a higher bond amount.

Additional amounts for bonds must be related to the economic value of the facility and the expected cost of decommissioning and site reclamation, as determined by the commission.

The commission may refuse to accept a bond if the operator or surety company has failed in the past to comply with all laws, rules and regulations, and orders of the commission; if a civil or administrative action brought by the commission is pending against the operator or surety company; or for other good cause.

2.Saltwater handling facility sites or appropriate parts thereof must be fenced if required by the director. All fences installed within or around any facility must be constructed in a manner that promotes emergency ingress and egress.

3.All waste, recovered solids, and fluids must be stored and handled in such a manner to prevent runoff or migration offsite.

4.Surface tanks may not be underground or partially buried, must be devoid of leaks, and constructed of or lined with materials resistant to the effects of produced saltwater liquids, brines, or chemicals that may be contained therein. The above materials requirement may be waived by the director for tanks presently in service and in good condition. Unused tanks and equipment must be removed from the site or placed into service, within a reasonable time period, not to exceed one year.

5.Dikes must be erected and maintained around saltwater tanks at any saltwater handling facility. Dikes must be erected around saltwater tanks at any new facility prior to introducing fluids. Dikes as well as the base material under the dikes and within the diked area must be constructed of sufficiently impermeable material to provide emergency containment. Dikes must be of sufficient dimension to contain the total capacity of the largest tank plus one day's fluid throughput. The required capacity of the dike may be lowered by the director if the necessity therefor can be demonstrated to the director's satisfaction. The operations of the saltwater handling facility must be conducted in such a manner as to prevent leaks, spills, and fires. Discharged liquids or brines must be properly removed and may not be allowed to remain standing within or outside of any diked areas. All such incidents must be properly cleaned up, subject to approval by the director. All such reportable incidents must be promptly reported to the director and a detailed account of any such incident must be filed with the director in accordance with section 43-02-03-30.

6.Within one hundred eighty days from the date the operator is notified by the commission, a perimeter berm, at least six inches [15.24 centimeters] in height, must be constructed of sufficiently impermeable material to provide emergency containment around the facility and to divert surface drainage away from the site. The director may consider an extension of time to implement these requirements if conditions prevent timely construction or a modification of these requirements if other factors are present that provide sufficient protection from environmental impacts.

7.The operator shall take steps to minimize the amount of solids stored at the facility.

8.Within thirty days following construction or modification of a saltwater handling facility, a facility sundry notice must be submitted detailing the work and the dates commenced and completed.

The facility sundry notice must be accompanied by a schematic drawing of the saltwater handling facility site drawn to scale, detailing all facilities and equipment, including the size, location, and purpose of all tanks; the height and location of all dikes as well as a calculated containment volume; all areas underlain by a synthetic liner; any leak detection system installed; the location of all flowlines; the stockpiled topsoil location and its volume; and the road access to the nearest existing public road.

9.Immediately upon the commissioning of the saltwater handling facility, the operator shall notify the director in writing of such date.

10.The operator of a saltwater handling facility shall provide continuing surveillance and conduct such monitoring and sampling as the director may require.

11.Storage pits, waste pits, or other earthen storage areas must be prohibited unless authorized by an appropriate regulatory agency. A copy of said authorization must be filed with the

12.Burial of waste at any saltwater handling facility site is prohibited. All residual water and waste, fluid or solid, must be disposed of in an authorized facility.

13.If deemed necessary by the director, the operator shall cause to be analyzed any waste substance contained onsite. Such chemical analysis must be performed by a certified laboratory and must adequately determine if chemical constituents exist which would categorize the waste as hazardous by department of environmental quality standards.

14.Saltwater handling facilities must be constructed and operated so as not to endanger surface or subsurface water supplies or cause degradation to surrounding lands and must comply with

section 43-02-03-28 concerning fire hazards and proximity to occupied dwellings.

15.All proposed changes to any saltwater handling facility are subject to prior approval by the

16.Any salable crude oil recovered from a saltwater handling facility must be reported on a skim oil report.

17.The operator shall comply with all laws, rules and regulations, and orders of the commission.

All rules in this chapter governing oil well sites also apply to any saltwater handling facility site.

18.The operator immediately shall cease operations if so ordered by the director for the failure to comply with the statutes of North Dakota, commission rules or orders, or directives of the

Notice of intention to abandon. The operator or the operator's agent shall file a notice of intention (form 4) to abandon and obtain the approval of the director, prior to the commencement of reclamation operations pursuant to section 43-02-03-34.1.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; September 1, 2000; July 1, 2002; May 1, 2004; April 1, 2010; April 1, 2012; October 1, 2016; April 1, 2020. 43-02-03-53.1. Saltwater handling facility permit requirements.
• History: Effective October 1, 2016; amended effective April 1, 2020; April 1, 2024. 43-02-03-53.2. Saltwater handling facility siting.
• History: Effective October 1, 2016. 43-02-03-53.3. Saltwater handling facility construction and operation requirements - Bond requirement.
• History: Effective October 1, 2016; amended effective April 1, 2018; April 1, 2020; April 1, 2026. 43-02-03-53.4. Saltwater handling facility abandonment and reclamation requirements.
• History: Effective October 1, 2016; amended effective April 1, 2018.

N.D. Admin. Code 43-02-03-54 Investigative powers

Upon receipt of a written complaint from any surface owner or lessee, royalty owner, mineral owner, local, state, or federal official, alleging a violation of the oil and gas conservation statutes or any rule,

regulation, or order of the commission, the director shall within a reasonable time reply in writing to the person who submitted the complaint stating that an investigation of such complaint will be made or the reason such investigation will not be made. The person who submitted the complaint may appeal the decision of the director to the commission. The director may also conduct such investigations on the director's own initiative or at the direction of the commission. If, after such investigation, the director affirms that cause for complaint exists, the director shall report the results of the investigation to the person who submitted the complaint, if any, to the person who was the subject of the complaint and to the commission. The commission shall institute such legal proceedings as, in its discretion, it believes are necessary to enjoin further violations.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; April 1, 2012.
• General Authority: NDCC 38-08-04, 38-08-12
• Law Implemented: NDCC 38-08-04, 38-08-12

N.D. Admin. Code 43-02-03-55 Abandonment of wells, treating plants, underground gathering pipelines, or saltwater handling facilities - Suspension of drilling

1.The removal of production equipment or the failure to produce oil or gas for one year constitutes abandonment of the well. The removal of production equipment or the failure to produce water from a source well for one year constitutes abandonment of the well. The removal of injection equipment or the failure to use an injection well for one year constitutes abandonment of the well. The removal of monitoring equipment from or the failure to use a subsurface observation well for one year constitutes abandonment of the well. The failure to plug a stratigraphic test hole within one year of reaching total depth constitutes abandonment of the well. The removal of treating plant equipment or the failure to use a treating plant for one year constitutes abandonment of the treating plant. The removal of saltwater handling facility equipment or the failure to use a saltwater handling facility for one year constitutes abandonment of the saltwater handling facility. An abandoned well must be plugged and its site must be reclaimed, an abandoned treating plant must be removed and its site must be reclaimed, and an abandoned saltwater handling facility must be removed and its site must be reclaimed, pursuant to sections 43-02-03-34 and 43-02-03-34.1. A well not producing oil or natural gas in paying quantities for one year may be placed in abandoned-well status pursuant to subsection 1 of North Dakota Century Code section 38-08-04. If an injection well is inactive for extended periods of time, the commission may, after notice and hearing, require the injection well to be plugged and abandoned. If an underground gathering pipeline is inactive for seven years, the commission may, after notice and hearing, require the pipeline to be properly abandoned pursuant to sections 43-02-03-29 and 43-02-03-29.1.

2.The director may waive for one year the requirement to plug and reclaim an abandoned well by giving the well temporarily abandoned status for good cause. If a well is given temporarily abandoned status, the well's perforations must be isolated, the integrity of its casing must be proven, and its casing must be sealed at the surface, all in a manner approved by the director.

The director may extend a well's temporarily abandoned status and each extension may be approved for up to one year. A fee of one hundred dollars shall be submitted for each application to extend the temporary abandonment status of any well. A surface owner may request a hearing to review a well temporarily abandoned for at least seven years pursuant to subsection 1 of North Dakota Century Code section 38-08-04. Temporarily abandoned status for oil and gas wells may be given only to wells that are to be used for purposes related to the production of oil and gas within the next seven years.

3.The director may approve an oil well for enhanced oil recovery potential status if the subject oil well was completed with surface casing set and cemented to properly isolate the Fox Hills formation, additional strings of casing are properly cemented to adequately protect and isolate all formations containing water, oil, or gas or any combination of these, protect the pipe through salt sections encountered, and isolate the uppermost sand of the Dakota group, and the director has deemed the subject well to have a potential use in an enhanced oil recovery project. If a well is given enhanced oil recovery potential status, the well's perforations must be isolated, the integrity of its casing must be proven, and its casing must be sealed at the surface, all in a manner approved by the director. A surface owner may request a hearing to review a well that has been on enhanced oil recovery potential status for at least twelve years, pursuant to subsection 1 of North Dakota Century Code section 38-08-04.

4.In addition to the waiver in subsection 2, the director may also waive the duty to plug and reclaim an abandoned well for any other good cause found by the director. If the director exercises this discretion, the director shall set a date or circumstance upon which the waiver expires.

5.The director may approve suspension of the drilling of a well. If suspension is approved, a plug must be placed at the top of the casing to prevent any foreign matter from getting into the well. When drilling has been suspended for thirty days, the well, unless otherwise authorized by the director, must be plugged and its site reclaimed pursuant to sections 43-02-03-34 and 43-02-03-34.1.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1990; May 1, 1992; August 1, 1999; January 1, 2008; April 1, 2010; April 1, 2012; April 1, 2014; October 1, 2016; April 1, 2018; April 1, 2020; April 1, 2022; April 1, 2024.

N.D. Admin. Code 43-02-03-56 Underground disposal of water

N.D. Admin. Code 43-02-03-57 Determination of gas well potential

After the completion or recompletion of a gas well, the operator shall conduct tests to determine the daily open flow potential of the well. The test results together with an analyses of the gas shall be reported to the director within thirty days after completion of the well.

Operators shall conduct either a stabilized one-point back-pressure test or a multipoint back-pressure test in accordance with the "Manual of Back-Pressure Testing of Gas Wells" published by the interstate oil and gas compact commission unless otherwise approved by the director.

History

• History: Amended effective January 1, 1983; May 1, 1992; September 1, 2000.

N.D. Admin. Code 43-02-03-58 Method and time of shut-in pressure tests

N.D. Admin. Code 43-02-03-59 Production from gas wells to be measured and reported

Gas production may not be transported from gas well premises until its volume has been determined through the use of properly calibrated measurement equipment. All measurement equipment and volume determinations must conform to American gas association standards and corrected to a pressure of fourteen and seventy-three hundredths pounds per square inch absolute [1034.19 grams per square centimeter] at a base temperature of sixty degrees Fahrenheit [15.56 degrees Celsius]. Gas produced, used on lease, or flared must be reported pursuant to sections 43-02-03-44 and 43-02-03-52.1.

September 1, 2000; April 1, 2026.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; May 1, 1994; July 1, 1996;

N.D. Admin. Code 43-02-03-60 Natural gas utilization. 43-02-03-60.1. Valuation of flared gas

The value of gas flared from an oil well in violation of North Dakota Century Code section 38-08-06.4 shall be determined by the commission after notice and hearing.

The connection of a well to a natural gas gathering line is "economically infeasible" under North Dakota Century Code section 38-08-06.4, if the direct costs of connecting the well to the line and the direct costs of operating the facilities connecting the well to the line during the life of the well, are greater than the amount of money the operator is likely to receive for the gas, less production taxes and royalties, should the well be connected. In making this calculation, the applicant may add ten percent to the amount of the cost of connecting the well and of operating the connection facilities used to determine whether a connection is economically infeasible. This ten percent may be added in consideration of the cost of money and other overhead costs that are not figured in the direct costs of connecting the well and operating the connecting facilities.

An applicant for an exemption under North Dakota Century Code section 38-08-06.4 must, at the minimum, present evidence covering the following areas:

1.Basis for the gas price used to determine whether it is economically infeasible to connect the well to a natural gas gathering line;

2.Cost of connecting the well to the line and operating the facilities connecting the well to the line;

3.Current daily rate of the amount of gas flared;

4.The amount of gas reserves and the amount of gas available for sale;

5.Documentation that it is economically infeasible to equip the well with an electrical generator to produce electricity from gas; and

6.Documentation that it is economically infeasible to equip the well with a system that intakes seventy-five percent of the gas and natural gas liquids volume from the well for beneficial consumption by means of compression to liquid for use as fuel, transport to a processing facility, production of petrochemicals or fertilizer, conversion to liquid fuels, and separating and collecting over fifty percent of the propane and heavier hydrocarbons.

Any operator desiring to certify a well for purposes of eligibility for the gas tax incentive provided in North Dakota Century Code chapter 57-51 shall submit to the director an application for certification as an oil or gas well employing a system to avoid flaring. The operator has the burden of establishing entitlement to certification and shall submit all data necessary to enable the commission to determine whether a well is entitled to the tax exemption.

An application for a temporary gas tax exemption under North Dakota Century Code chapter 57-51 must, at the minimum, include the following information:

1.Name and address of the applicant and name and address of the person operating the well, if different.

2.Name and number of the well and the legal description of the location of the well for which a certification is requested.

3.If gas is collected and used at a well or facility site to power an electrical generator, the following information must be included:

a.Name and manufacturer of the electrical generator.

b.Date electrical generation commenced.

c.Volume of gas consumed by the electrical generator during a minimum seven-day test period and the volume of gas produced by the well during such test period.

4.If gas is collected at a well or facility site by a system that compresses gas and natural gas liquids for beneficial consumption, the following information must be included:

a.Name and manufacturer of the compression equipment.

b.Date compression commenced.

c.Destination of the compressed products (i.e., fuel use, processing facility, fertilizer plant, etc.).

d.Volume of gas compressed during a minimum seven-day test period and the amount of gas produced by the well during such test period.

e.Analysis of a representative gas sample produced from the well.

5.If gas is collected at a well or facility site for a value-added process that will reduce the volume or intensity of a flare by more than sixty percent, the following information must be included:

a.Name and manufacturer of the process equipment.

b.Date processing commenced.

c.Volume of gas processed during a minimum seven-day test period and the amount of gas produced by the well during such test period.

d.Analysis of a representative gas sample produced from the well, detailing the Btu value of the unprocessed gas and volume or mass as well as Btu value of each component removed from the flared gas stream for value added use.

If the application does not contain sufficient information to make a determination, the director may require the applicant to submit additional information.

History

• History: Effective October 1, 1990; amended effective May 1, 1992; May 1, 1994; May 1, 2004.
• Law Implemented: NDCC 38-08-06.4 43-02-03-60.2. Flaring exemption.
• History: Effective May 1, 1994; amended effective April 1, 2014.
• General Authority: NDCC 38-07-04
• Law Implemented: NDCC 38-08-06.4 43-02-03-60.3. Application to certify well for temporary gas tax exemption.
• History: Effective April 1, 2014.
• Law Implemented: NDCC 38-08-04, 57-51-02.6

N.D. Admin. Code 43-02-03-61 Storage gas

With the exception of the requirement to meter and report monthly the amount of gas injected and the amount of gas withdrawn from storage, in the absence of waste, this chapter shall not apply to gas being injected into or removed from storage.

N.D. Admin. Code 43-02-03-62 Carbon dioxide, coal bed methane, helium, and nitrogen

Insofar as is applicable, the provisions of this chapter relating to gas, gas wells, and gas reservoirs shall also apply to carbon dioxide, coal bed methane, helium, nitrogen, carbon dioxide wells, coal bed methane wells, helium wells, nitrogen wells, carbon dioxide reservoirs, coal bed methane reservoirs, helium reservoirs, and nitrogen reservoirs.

History

• History: Amended effective January 1, 1983; September 1, 1987; July 1, 2002.

N.D. Admin. Code 43-02-03-63 Regulation of pools

To prevent waste and to protect correlative rights, when the commission finds that total production in an area significantly exceeds the reasonable market demand and undue marketing discrimination is occurring, the commission may prorate or distribute the allowable production among proration units upon a reasonable basis through rules, regulations, or orders pertaining to any pool or area after notice and hearing.

N.D. Admin. Code 43-02-03-64 Rate of producing wells

In allocated oil and gas pools the owner or operator of any proration unit shall not produce from the unit during any proration period more oil or gas than the allowable production from such unit as shown by the proration schedule, provided that such owners or operators shall be permitted to maintain a uniform rate of production for each unit during the proration period. In order to maintain a uniform rate of production from the pool during any proration period, any operator may produce a total volume of oil and gas equal to that shown on the applicable proration schedule plus five days unit allowable, and any such overproduction may be deducted from the total allowable for the well in the second month following.

Where the commission has established spacing rules in any pool, proration units shall consist of spacing units.

History

• History: Amended effective January 1, 1983; September 1, 2000; January 1, 2008; April 1, 2008.

N.D. Admin. Code 43-02-03-65 Authorization for production, purchase, and transportation

When necessary the commission shall hold a hearing to set proration unit allowables for the state.

The commission shall consider all evidence of market demand for oil and gas, including sworn statements of individual demand as submitted by each purchaser or buyer in the state, and determine the amount to be produced from all pools. The amount so determined will be allocated among the various pools in accordance with existing regulations and in each pool in accordance with regulations governing each pool. In allocated pools, effective the first day of each proration period, the commission will issue a proration schedule which will authorize the production of oil and gas from the various units in strict accordance with the schedule, and the purchase and transportation of such production.

Allowable for wells completed after the first day of the proration period will become effective from the date of well completion. A supplementary order will be issued by the commission to the operator of a newly completed or recompleted well, and to the purchaser or transporter of the production from a newly completed or recompleted well, establishing the effective date of completion, the amount of production permitted during the remainder of the proration period, and the authority to purchase and transport same from said proration unit.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; July 1, 1996; January 1, 2008.

N.D. Admin. Code 43-02-03-66 Application for allowable on new oil wells

No well shall be placed on the proration schedule until a completion report (form 6 or form provided by the commission) has been filed with the director.

The discovery well of any pool hereafter discovered shall be allowed to produce at a maximum efficient rate until such time as proper spacing is set for the pool, and shall produce thereafter, only pursuant to the general proration rules and regulations of the commission.

January 1, 2008; April 1, 2020.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; September 1, 2000;

N.D. Admin. Code 43-02-03-67 Oil proration

At the beginning of each calendar month, the distribution or proration to the respective proration units shall be changed in order to take into account all new wells which have been completed and were not in the proration schedule during the previous calendar month. Where any well is completed between the first and last day of the calendar month, its proration unit shall be assigned an allowable beginning at seven a.m., on the date of completion and for the remainder of that calendar month.

N.D. Admin. Code 43-02-03-68 Gas-oil ratio limitation

In allocated pools containing a well or wells producing from a reservoir which contains both oil and gas, each proration unit shall be permitted to produce only that volume of gas equivalent to the applicable limiting gas-oil ratio multiplied by the proration unit oil allowable currently assigned to the pool. In the event the commission has not set a gas-oil ratio limit for a particular oil pool, the limiting gas-oil ratio shall be two thousand cubic feet [56.63 cubic meters] of gas for each barrel of oil produced.

A gas-oil limit shall be placed on all allocated oil pools, and all proration units having a gas-oil ratio exceeding the limit for the pool shall be adjusted unless previously exempted by the commission after hearing, in accordance with the following formula:

1.Any proration unit which, on the basis of the latest official gas-oil ratio test has a gas-oil ratio in excess of the limiting gas-oil ratio for the pool in which it is located, shall be permitted to produce that number of barrels of oil which shall be determined by multiplying the proration unit allowable by the fraction, the numerator of which shall be the limiting gas-oil ratio for the pool and the denominator of which shall be the official gas-oil ratio test of the well.

2.Any unit containing a well or wells producing from a reservoir which contains both oil and gas shall be permitted to produce only that volume of gas equivalent to the applicable limiting gas-oil ratio multiplied by the proration unit allowable currently assigned to the pool.

All proration units to which gas-oil ratio adjustments are applied shall be so indicated in the proration schedule with adjusted allowables stated. The adjustment shall be made effective on the first day of the month following that in which the gas-oil ratio tests were reported for the pool, as set forth in the special field rules applicable to the pool.

In cases of new pools the limiting gas-oil ratio shall be two thousand cubic feet [56.63 cubic meters] per barrel until such time as changed by the commission after a hearing. After notice and hearing, the commission shall determine or redetermine, the specific gas-oil ratio limit which is applicable to a particular allocated oil pool.

N.D. Admin. Code 43-02-03-69 Allocation of gas production

When the commission determines that allocation of gas production in a designated gas pool is necessary to prevent waste, and to protect correlative rights, the commission, after notice and hearing, shall consider the nominations of purchasers from that gas pool and other relevant data, and shall fix the allowable production of that pool, and shall allocate production among the proration units in the pool delivering to a gas transportation facility upon a reasonable basis.

The commission shall include in the proration schedule of such pool any proration unit which it finds is being unreasonably discriminated against through denial of access to a gas transportation facility which is reasonably capable of handling the type of gas producible from such proration unit.

N.D. Admin. Code 43-02-03-70 Gas proration period

The gas proration period shall be set by order of the commission.

N.D. Admin. Code 43-02-03-71 Adjustment of gas allowables

When the actual market demand from any allocated gas pool during a proration period is more than or less than the allowable set by the commission for the pool for the period, the commission shall adjust the gas proration unit allowables for the pool for the next proration period so that each gas proration unit shall have a reasonable opportunity to produce its fair share of the gas production from the pool in a manner that shall protect correlative rights.

N.D. Admin. Code 43-02-03-72 Gas proration units

Before issuing a proration schedule for an allocated gas pool, the commission, after notice and hearing, shall fix the gas proration unit for that pool.

N.D. Admin. Code 43-02-03-73 Permit for injection of gas, air, or water

N.D. Admin. Code 43-02-03-74 Casing and cementing of injection wells

N.D. Admin. Code 43-02-03-75 Notice of commencement and discontinuance of injection operations

N.D. Admin. Code 43-02-03-76 Records

N.D. Admin. Code 43-02-03-77 Application for unitized management under commission order

Any plan of unitized management or any injection into a reservoir for the purpose of maintaining reservoir pressure or for enhanced recovery operations shall be permitted only by order of the commission after notice and hearing. The application for an order shall include a complete statement of all matters required by North Dakota Century Code section 38-08-09 et seq.

The application shall be submitted to the commission, in duplicate, at least forty-five days prior to the date requested for such hearings and shall be accompanied by all engineering, geological, and other technical exhibits which will be introduced at the hearing.

In addition, the application shall set forth that all the provisions of North Dakota Century Code

section 38-08-09.5 have been complied with.

History

• History: Amended effective November 1, 1982; January 1, 1983; May 1, 1992.
• General Authority: NDCC 38-08-09
• Law Implemented: NDCC 38-08-09

N.D. Admin. Code 43-02-03-78 Illegal sale prohibited

N.D. Admin. Code 43-02-03-79 Purchase of liquids from gas wells

Provided that a supplemental order is issued authorizing such production on the proration schedule, any common purchaser is authorized to purchase one hundred percent of the amount of associated crude oil or condensate produced and recovered from a gas proration unit.

History

• General Authority: NDCC 38-08-06
• Law Implemented: NDCC 38-08-06

N.D. Admin. Code 43-02-03-80 Reports of purchasers and transporters of crude oil

1.By five p.m. on the first day of the second month succeeding the month in which oil is removed, purchasers and transporters, including truckers, shall file with the director the appropriate monthly reporting forms. The purchaser shall file on the oil purchasers monthly report and the transporter on the oil transporters monthly report the amount of all crude oil removed and purchased by them from each well, central production facility, treating plant, or saltwater handling facility during the reported month. The transporter shall report the disposition of such crude oil on an oil transporters and storers monthly report (form 10b). All meter and tank measurements, and volume determinations of crude oil removed and purchased from a well or central production facility must conform to American petroleum institute standards and corrected to a base temperature of sixty degrees Fahrenheit [15.56 degrees Celsius] and fourteen and seventy-three hundredths pounds per square inch absolute [1034.19 grams per square centimeter].

2.Prior to removing any oil, purchasers and transporters shall obtain an approved copy of a producer's authorization to purchase and transport oil from either the producer or the director.

3.The operator of any oil rail facility shall report the amount of oil received and shipped out of such facility on form 10rr.

July 1, 1996; September 1, 2000; April 1, 2014; October 1, 2016; April 1, 2026. 43-02-03-80.1. Gas purchaser report.

By five p.m. on the fifth day of the second month succeeding the month in which gas is purchased from a well or central production facility, gas purchasers shall file with the director a gas purchasers report (form 12a) of all gas purchased from each well or central production facility during the reported month. All volumes of gas must be reported in units of one thousand cubic feet [28.32 cubic meters] computed at a pressure of fourteen and seventy-three hundredths pounds per square inch absolute [1034.19 grams per square centimeter] at a base temperature of sixty degree Fahrenheit [15.56 degrees Celsius]. All measurement equipment and volume determinations must conform to American petroleum institute or American gas association standards, or with the meter manufacturer's recommendations.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1990; May 1, 1992; May 1, 1994;
• History: Effective April 1, 2026.

N.D. Admin. Code 43-02-03-81 Authorization to transport oil from a well, treating plant, central production facility, or saltwater handling facility

1.Crude oil may not be transported from a well, treating plant, central production facility, or saltwater handling facility, prior to the director's approval of the authorization to purchase and transport oil form unless verbally approved by the director.

2.After notice and hearing pursuant to sections 43-02-03-88.2 through 43-02-03-101, the commission may revoke the authorization to purchase and transport oil for failure to comply with any rule, regulation, directive of the director, or order of the commission.

3.Oil transported before the authorization is obtained or if such authorization has been revoked is considered illegal oil.

Transporters of and purchasers for the resale of dry gas shall file a report (form 8a) with the director showing the amount of gas taken from each plant or well during the monthly reporting period.

All gas shall be reported monthly to the director in one thousand cubic feet [28.32 cubic meters] computed at a pressure of fourteen and seventy-three hundredths pounds per square inch [1034.19 grams per square centimeter] absolute at a base temperature of sixty degrees Fahrenheit [15.56 degrees Celsius].

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; July 1, 1996; September 1, 2000; April 1, 2014; October 1, 2016; April 1, 2026. 43-02-03-81.1. Reports of purchases for resale and transporting of dry gas.
• History: Effective January 1, 1983; amended effective May 1, 1992; July 1, 1996.

N.D. Admin. Code 43-02-03-82 Refinery reports

Each refiner of oil within North Dakota shall furnish for each calendar month a report (form 13) containing information and data respecting crude oil and products involved in such refiner's operations during each month. The report for each month shall be prepared and filed on or before the fifteenth of the next succeeding month with the director.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; September 1, 2000.

N.D. Admin. Code 43-02-03-83 Gas processing plant reports

Each operator of a gas processing plant, cycling plant, or any other plant at which natural gas is received and processed shall report to the director the amount of natural gas received, disposition of the natural gas, and the plant production that includes condensate, ethane, propane, butane, natural gasoline, kerosene, oil, sulfur, or other products on a gas plant report (form 12) by five p.m. on the fifth day of the second month following the month in which gas is processed.

Crude oil recovered must be reported to the director, on an oil report by five p.m. on the first day of the second month succeeding the month in which oil is removed. Other operations must be reported to the director, on form 12, by five p.m. on the fifth day of the second month following the month in which gas is processed.

History

• History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; April 1, 2026.

N.D. Admin. Code 43-02-03-84 Additional information may be required

This chapter shall not be taken or construed to limit or restrict the authority of the commission to require the furnishing of such additional reports, data, or other information relative to production, transportation, storing, refining, processing, or handling of crude oil, gas, or products as may appear to be necessary or desirable, either generally or specifically, for the prevention of waste, protection of correlative rights, and the conservation of natural resources.

N.D. Admin. Code 43-02-03-85 Books and records to be kept to substantiate reports

All producers, transporters, storers, refiners, gasoline or extraction plant operators, and initial purchasers within North Dakota shall make and keep appropriate books and records for a period not less than six years, covering their operations in North Dakota from which they may be able to make and substantiate the reports required by this chapter.

History

• History: Amended effective January 1, 1983; July 1, 2002.

N.D. Admin. Code 43-02-03-86 Public hearing required

N.D. Admin. Code 43-02-03-87 Institute proceedings

N.D. Admin. Code 43-02-03-88 Application for hearing

In any proceeding instituted upon application, the application shall be signed by the applicant or by the applicant's attorney. An application shall state (1) the name and general description of the common source or sources of supply affected by the order, rule, or regulation sought if any, unless same is intended to apply to and affect the entire state, in which event the application shall so state, and such statement shall constitute sufficient description; and (2) briefly the general nature of the order, rule, or

regulation sought in the proceedings.

1.Applications to amend field rules to allow additional wells on existing spacing units, for pooling under North Dakota Century Code section 38-08-08, for a flaring exemption under North Dakota Century Code section 38-08-06.4 and section 43-02-03-60.2, for underground injection under chapter 43-02-05, for commingling in one well bore the fluids from two or more pools under section 43-02-03-42, for converting a mineral well to a freshwater well under

section 43-02-03-35, for establishing central tank batteries or central production facilities under section 43-02-03-48.1, and for recovery of a risk penalty for which there is no known opposition under section 43-02-03-16.3 must be signed by the applicant or the applicant's representative. The application must contain or refer to attachments that contain all the information required by law as well as the information the applicant wants the commission to consider in deciding whether to grant the application. The application must designate an employee or representative of the applicant to whom the commission can direct inquiries regarding the application.

2.The commission shall give the county auditor notice at least fifteen days prior to the hearing of any application in which a request for a disposal under chapter 43-02-05 is received.

3.The applications referred to in subsection 1 will be advertised and scheduled for hearing as are all other applications received by the commission. The applicant, however, unless required by the director, need not appear at the hearing scheduled to consider the application, although additional evidence may be submitted prior to the hearing. Any interested party may appear at the hearing to oppose or comment on the application. Any interested party may also submit written comments on or objections to the application prior to the hearing date. Such submissions must be received no later than five p.m. on the last business day prior to the hearing date and may be part of the record in the case if allowed by the hearing examiner.

4.The director is authorized, on behalf of the commission, to grant or deny the applications referred to in subsection 1.

5.In any proceeding under this section, the applicant, at the hearing, may supplement the record by offering testimony and exhibits in support of the application.

6.In the event the applicant is not required by the director to appear at the hearing and an interested party does appear to oppose the application or submits a written objection to the application, the hearing examiner shall continue the hearing to a later date, keep the record open for the submission of additional evidence, or take any other action necessary to ensure the applicant, who does not appear at the hearing as the result of subsection 3, is accorded due process.

In any hearing, the commission may, at its discretion, allow remote communication or communication by other reliable electronic means of witnesses and interested parties. The procedure is as follows:

1.Notice of an applicant's witness appearing by remote communication or communication by other reliable electronic means must be submitted in writing at least two business days prior to the hearing date.

2.Notice of an interested party appearing by remote communication or communication by other reliable electronic means must be submitted in writing to the applicant and the commission at least three business days prior to the hearing date. The notice must include the subject hearing, the name and telephone number of the interested party, and the name and telephone number of the interested party's attorney or representative that will be present at the hearing.

3.The hearing examiner may disallow remote communication or communication by other reliable electronic means and may schedule or reschedule for an in-person hearing.

4.All parties participating by remote communication or communication by other reliable electronic means shall have an attorney or representative present at the hearing who is responsible for providing the commission at the time of the hearing with any documentary evidence requested to be included in the record, and for any other matters necessary for the party to participate by remote communication or communication by other reliable electronic means. This requirement may be waived at the discretion of the hearing examiner for good cause.

5.All parties participating by remote communication or communication by other reliable electronic means shall file an affidavit verifying the identity of such party. The record of such remote communication or communication by other reliable electronic means is not considered evidence in the case unless said affidavit is received by the commission prior to an order being issued by the commission. The commission shall provide a form affidavit. The commission may refuse to consider all or any part of the information received from any party participating by remote communication or communication by other reliable electronic means.

6.For all hearings allowing remote communication or communication by other reliable electronic means, the commission shall provide a hearing room equipped with remote communication equipment.

History

• Law Implemented: NDCC 38-08-11 43-02-03-88.1. Special procedures for increased density wells, pooling, flaring exemption, underground injection, commingling, converting mineral wells to freshwater wells, central tank battery or central production facilities, and unopposed recovery of a risk penalty applications.
• History: Effective May 1, 1992; amended effective May 1, 1994; May 1, 2004; April 1, 2012; April 1, 2014; April 1, 2018; April 1, 2022; April 1, 2026.
• General Authority: NDCC 38-08-04, 38-08-11
• Law Implemented: NDCC 38-08-04, 38-08-08 43-02-03-88.2. Hearing participants by remote communication or other reliable electronic means.
• History: Effective July 1, 2002; amended effective May 1, 2004; April 1, 2026.
• Law Implemented: NDCC 28-32-11

N.D. Admin. Code 43-02-03-89 Upon application hearing is set

N.D. Admin. Code 43-02-03-90 Hearings - Complaint proceedings - Emergency proceedings - Other proceedings

1.Except as more specifically provided in North Dakota Century Code section 38-08-11, the rules of procedure established in subsection 1 of North Dakota Century Code section 28-32-21 apply to proceedings involving a complaint and a specific-named respondent.

2.For proceedings that do not involve a complaint and a specific-named respondent the commission shall give at least fifteen days' notice (except in emergency) of the time and place of hearing thereon by one publication of such notice in a newspaper of general circulation in Bismarck, North Dakota, and in a newspaper of general circulation in the county where the land affected or some part thereof is situated, unless in some particular proceeding a longer period of time or a different method of publication is required by law, in which event such period of time and method of publication shall prevail. The notice shall issue in the name of the commission and shall conform to the other requirements provided by law.

3.In case an emergency is found to exist by the commission which in its judgment requires the making of a rule or order without first having a hearing, the emergency rule or order shall have the same validity as if a hearing with respect to the same had been held after notice. The emergency rule or order permitted by this section shall remain in force no longer than forty days from its effective date, and in any event, it shall expire when the rule or order made after due notice and hearing with respect to the subject matter of such emergency rule or order becomes effective.

Any person moving for a continuance of a hearing, and who is granted a continuance, shall submit a twenty-five dollar fee to the commission, or if the cost of republication exceeds fifty dollars the commission may bill the applicant, to pay the cost of republication of notice of the hearing.

July 1, 1996; July 1, 2002; October 1, 2016.

The commission may hold investigatory hearings upon the institution of a proceeding by application or by motion of the commission. Notice of the hearing must be served upon all parties personally or by certified mail at least five days before the hearing. 43-02-03-90.2. Official record.

The evidence in each case heard by the commission, unless specifically excluded by the hearing examiner, includes the certified directional surveys, and all oil, water, and gas production records, and all injection records on file with the commission.

Any interested party may submit written comments on or objections to the application prior to the hearing date. Such submissions must be received no later than five p.m. on the last business day prior to the hearing date and may be part of the record in the case if allowed by the hearing examiner.

Settlement negotiations between parties to a contested case are only admissible as governed by North Dakota Century Code section 28-32-24, although the hearing examiner may strike such testimony from the record for good cause.

Neither petitions for review of a recommended order nor oral arguments following issuance of a recommended order and pending issuance of a final order are allowed. 43-02-03-90.4. Notice of order by mail.

The commission shall give notice of an order, and findings and conclusions upon which it is based, to all parties pursuant to North Dakota Century Code section 38-08-11.

All pleadings, notices, written motions, requests, petitions, briefs, and correspondence to the commission or commission employee from a party (or vice versa) relating to a proceeding after its commencement, must be filed with the director and entered into the commission's official record of the procedure provided the record is open at the time of receipt. All parties shall receive copies upon request of any or all of the evidence in the record of the proceedings. The commission may charge for the actual cost of providing copies of evidence in the record. Unless otherwise provided by law, filing shall be complete when the material is entered into the record of the proceeding.

History

• History: Amended effective March 1, 1982; January 1, 1983; May 1, 1990; May 1, 1992; May 1, 1994;
• Law Implemented: NDCC 28-32-05, 38-08-11 43-02-03-90.1. Investigatory hearings.
• History: Effective May 1, 1992; amended effective April 1, 2010; April 1, 2012; October 1, 2016; April 1, 2022.
• General Authority: NDCC 28-32-06
• Law Implemented: NDCC 28-32-06 43-02-03-90.3. Petitions for review of recommended order and oral arguments prohibited.
• History: Effective May 1, 1992; amended effective April 1, 2022. 43-02-03-90.5. Service and filing.

N.D. Admin. Code 43-02-03-91 Rehearing

Repealed effective May 1, 1992.

N.D. Admin. Code 43-02-03-92 Burden of proof

N.D. Admin. Code 43-02-03-93 Designation of examiners

The commission may by motion designate and appoint qualified individuals to serve as examiners.

The commission may refer any matter or proceeding to any legally designated and appointed examiner or examiners.

History

• History: Amended effective April 30, 1981; January 1, 1983.

N.D. Admin. Code 43-02-03-94 Matters to be heard by examiner

N.D. Admin. Code 43-02-03-95 Powers and duties of examiner

The commission may by motion limit the powers and duties of any examiner in any particular case to such issues or to the performance of such acts as the commission deems expedient; however, subject only to such limitation as may be ordered by the commission, the examiner or examiners to whom any matter or proceeding is referred under this chapter shall have full authority to hold hearings on such matter or proceeding in accordance with and pursuant to this chapter. The examiner shall have the power to regulate all proceedings before the examiner and to perform all acts and take all measures necessary or proper for the efficient and orderly conduct of such hearing, including ruling on prehearing motions, the swearing of witnesses, receiving of testimony and exhibits offered in evidence, subject to such objections as may be imposed, and shall cause a complete record of the proceeding to be made and retained.

History

• History: Amended effective January 1, 1983; May 1, 1990.

N.D. Admin. Code 43-02-03-96 Matters heard by commission

N.D. Admin. Code 43-02-03-97 Examiner disinterested umpire

N.D. Admin. Code 43-02-03-98 Report of examiner

Upon the conclusion of any hearing before an examiner, the examiner shall promptly consider the proceedings in such hearing, and based upon the record of such hearing, the examiner shall prepare a report and recommendations for the disposition of the matter or proceeding by the commission. Such report and recommendations shall either be accompanied by a proposed order or shall be in the form of a proposed order, and shall be submitted to the commission.

N.D. Admin. Code 43-02-03-99 Commission order from examiner hearing

After receipt of the report and recommendations of the examiner, the commission shall enter its order disposing of the matter or proceeding.

N.D. Admin. Code 43-02-03-100 Hearing de novo before commission

N.D. Admin. Code 43-02-03-101 Prehearing motion practice

In a matter pending before the commission, all prehearing motions must be served by the moving party upon all parties affected by the motion. Service must be upon a party unless a party is represented by an attorney, in which case service must be upon the attorney. Service must be made by delivering a copy of the motion and all supporting papers in conformance with one of the means of service provided for in rule 5(b) of the North Dakota Rules of Civil Procedure. Proof of service must be made as provided in rule 4 of the North Dakota Rules of Civil Procedure or by the certificate of an attorney showing that service has been made. Proof of service must accompany the filing of a motion.

Any motion filed without proof of service is not properly before the commission.

History

• History: Effective May 1, 1990; amended effective January 1, 2006.

Chapter 43-02-04 Natural Gas Well Status Determinations [Repealed]

N.D. Admin. Code 43-02-04 Natural Gas Well Status Determinations [Repealed]

CHAPTER 43-02-04

NATURAL GAS WELL STATUS DETERMINATIONS [Repealed effective July 1, 1996]

Chapter 43-02-05 Underground Injection Control

N.D. Admin. Code 43-02-05-01 Definitions

The terms used throughout this chapter have the same meaning as in chapter 43-02-03 and North Dakota Century Code chapter 38-08 except:

1."Area of review" means an area encompassing a fixed radius around the injection well, field, or project of not less than one-quarter mile [402.34 meters].

2."Underground injection" means the subsurface emplacement of fluids:

a.Which are brought to the surface in connection with natural gas storage operations, or conventional oil or natural gas production and may be commingled with wastewaters from gas plants which are an integral part of production operations, unless those waters are classified as a hazardous waste at the time of injection.

b.For enhanced recovery of oil or natural gas.

c.For storage of hydrocarbons which are liquids at standard temperature and pressure.

3."Underground source of drinking water" means an aquifer or any portion thereof which supplies drinking water for human consumption, or in which the ground water contains fewer than ten thousand milligrams per liter total dissolved solids and which is not an exempted aquifer.

All undergound injection wells are also subject to the provisions of chapter 43-02-03 where applicable.

History

• History: Effective November 1, 1982; amended effective May 1, 1994. 43-02-05-01.1. Application of rules for underground injection wells.
• History: Effective July 1, 1996.
• General Authority: NDCC 38-08-04
• Law Implemented: NDCC 38-08-04

N.D. Admin. Code 43-02-05-02 Injection into underground source of drinking water prohibited

Underground injection that causes or allows movement of fluid into an underground source of drinking water is prohibited, unless the underground source of drinking water is an exempted aquifer as provided in section 43-02-05-03.

History

• History: Effective November 1, 1982.

N.D. Admin. Code 43-02-05-03 Exempted aquifers

An aquifer or a portion thereof which meets the criteria for an underground source of drinking water may be determined by the commission, after notice and hearing, to be an exempted aquifer if it meets the following criteria:

1.It does not currently serve as a source of drinking water; and

2.It cannot now and will not in the future serve as a source of drinking water because:

a.It is mineral, hydrocarbon, or geothermal energy producing, or can be demonstrated by a permit applicant as part of a permit application for an underground injection permit to contain minerals or hydrocarbons that considering their quantity and location are expected to be commercially producible; or

b.It is situated at a depth or location which makes recovery of water for drinking water purposes economically or technologically impractical; or

c.It is so contaminated that it would be economically or technologically impractical to render that water fit for human consumption; or

3.The total dissolved solids content of the ground water is more than three thousand and less than ten thousand milligrams per liter and it is not reasonably expected to supply a public water system.

History

• History: Effective November 1, 1982; amended effective January 1, 1997.

N.D. Admin. Code 43-02-05-04 Permit requirements

1.No underground injection may be conducted, or site or access road construction commenced, without obtaining a permit from the director after notice and hearing. The application shall be on a form 14 or form provided by the director and shall include at least the following information:

a.The name and address of the operator of the injection well.

b.The surface and bottom hole location.

c.Appropriate geological data on the injection zone and the upper and lower confining zones including geologic names, lithologic descriptions, thicknesses, and depths.

d.The estimated bottom hole fracture pressure of the upper confining zone.

e.Average and maximum daily rate of fluids to be injected.

f.Average and maximum requested surface injection pressure.

g.Geologic name and depth to base of the lowermost underground sources of drinking water which may be affected by the injection.

h.Existing or proposed casing, tubing, and packer data.

i.Existing or proposed cement specifications, including amounts and actual or proposed top of cement.

j.A plat and maps depicting the area of review, (one-quarter-mile [402.34-meter] radius) and detailing the location, well name, and operator of all wells in the area of review. The plat and maps must include all injection wells, producing wells, plugged wells, abandoned wells, drilling wells, dry holes, permitted wells, water wells, surface bodies of water, and other pertinent surface features, such as occupied dwellings and roads.

k.A review of the surficial aquifers within one mile of the proposed injection well site or surface facilities.

l.A tabulation of data on all wells within the area of review that penetrate the proposed injection zone. Such data must include a description of each well's type, construction, date drilled, location, depth, record of plugging and completion, and any additional information the director may require. A detail of any corrective action necessary for any of the wells not properly cemented or plugged to prevent the movement of fluid out of the injection zone must also be included.

m.If faults are known or suspected, a cross section that includes a depiction of the fault at depth.

n.Proposed injection program, including method of transportation of the fluid to the injection facility and the injection well.

o.A tabulation of all freshwater wells and domestic freshwater sources within the area of review. Each freshwater well and domestic freshwater source must be identified by owner, location by quarter-quarter, section, township, and range, type of well or source, depth, and current status. A quantitative analysis from a state-certified laboratory of freshwater from the two nearest freshwater wells within a one-mile [1.61-kilometer] radius must be submitted. This requirement may be waived by the director in certain instances.

p.Quantitative analysis from a state-certified laboratory of a representative sample of water to be injected. A compatibility analysis with the receiving formation may also be required.

q.List identifying all source wells or sources of injectate.

r.A legal description of the land ownership within the area of review in both tabular and plat form.

s.An affidavit of mailing, and proof of service, certifying that all landowners within the area of review have been notified of the proposed injection well. A copy of the letter sent to each landowner must be attached to the affidavit.

If the proposed injection well is within an area permit authorized by a commission order, the notice shall inform the landowners within the area of review that comments or objections may be submitted to the commission within thirty days and must include a contact person and phone number for the applicant and a contact person and phone number for the commission.

If the proposed injection well is not within an area permit authorized by a commission order, the notice shall inform the landowners within the area of review that a hearing will be held at which comments or objections may be directed to the commission, and written comments or objections to the application may be submitted prior to the hearing date, received by the commission no later than five p.m. on the last business day prior to the hearing date.

t.An affidavit of mailing, and proof of service, certifying that all owners or operators of any usable oil and gas exploration and production well or permit within the area of review have been notified of the proposed injection well. A copy of the letter sent to each owner or operator must be attached to the affidavit.

If the proposed injection well is within an area permit authorized by a commission order, the notice must include the proposed surface and bottom hole locations of the proposed injection well and inform the owner or operator of any oil and gas exploration- and production-related well within the area of review that comments or objections may be submitted to the commission within thirty days and must include a contact person and phone number for the applicant and a contact person and phone number for the commission.

If the proposed injection well is not within an area permit authorized by a commission order, the notice must include the proposed surface and bottom hole locations of the proposed injection well and inform the owner or operator of any oil and gas productionrelated well within the area of review that a hearing will be held at which comments or objections may be directed to the commission, and that written comments or objections to the application may be submitted prior to the hearing date, received by the commission no later than five p.m. on the last business day prior to the hearing date.

u.All logging and testing data on the well which has not been previously submitted.

v.Schematic or other appropriate drawings and tabulations of the wellhead and surface facilities, including the size, location, construction, and purpose of all tanks, the height and location of all dikes and containment, including a calculated containment volume, all areas underlain by a synthetic liner, and the location of all flow lines and a tabulation of any pressurized flow line specifications. It must also include the proposed road access to the nearest existing public road and the authority to build such access.

w.A schematic drawing of the well detailing the proposed well bore construction, including the size of the borehole; the total depth and plug back depth; the casings and tubing sizes, weights, grades, and top and bottom depths; the perforated interval top and bottom depths; the packer depth; the injection zone and upper and lower confining zones' top and bottom depths.

x.Traffic flow diagram of the site, depicting sufficient area to contain all anticipated traffic.

y.A detailed drilling prognosis, including a drilling, casing, cementing, logging, testing, and coring program, if applicable.

z.A detailed description of the proposed completion or conversion procedure. aa.Any additional information necessary to demonstrate that injection into the proposed injection zone will not initiate fractures in the confining zone that could allow fluid movement out of the injection zone. bb.Any other information required by the director to evaluate the proposed well.

2.Permits may contain such terms and conditions as the director deems necessary.

3.The corrective action plan for any well in the area of review which is not properly cemented or plugged to prevent the movement of fluid out of the injection zone must be incorporated into the permit as a condition if the plan is deemed adequate by the director. If the director deems the plan inadequate, the director shall require the applicant to revise the plan, prescribe a plan for corrective action as part of the permit, or deny the application. Before injection commences in an injection well, the applicant shall complete any needed corrective action on wells penetrating the injection zone in the area of review to the satisfaction of the director.

4.Any permit issued under this section may be revoked by the commission after notice and hearing if the permittee fails to comply with the terms and conditions of the permit or any applicable rule or statute. Any permit issued under this section may be suspended by the director for good cause.

5.Before a permit for underground injection will be issued, the applicant must satisfy the director that the proposed injection well will not endanger any underground source of drinking water.

6.No person shall commence construction of an underground injection well, site, or access road without prior approval of the director.

7.Permits are transferable only with approval of the director.

8.Permits may be modified by the director.

9.All injection wells permitted before November 1, 1982, shall be deemed to have a permit for purposes of this section; however, all such prior permitted wells are subject to all other requirements of this chapter.

10.A permit shall automatically expire one year after the date it was issued, unless operations have commenced to complete the well as an injection well.

11.If the permitted injection zone is plugged and abandoned, the permit shall expire and be of no further force and effect.

May 1, 2004; January 1, 2006; April 1, 2014; October 1, 2016; April 1, 2020.

History

• History: Effective November 1, 1982; amended effective May 1, 1992; May 1, 1994; July 1, 1996;

N.D. Admin. Code 43-02-05-05 Siting

All injection wells shall be sited in such a fashion that they inject into a formation which has confining zones that are free of known open faults or fractures within the area of review.

History

• History: Effective November 1, 1982; amended effective April 1, 2014.

N.D. Admin. Code 43-02-05-06 Construction requirements

1.All injection wells shall be cased and cemented to prevent movement of fluids into or between underground sources of drinking water or into an unauthorized zone. The casing and cement used in construction of each new injection well shall be designed for the life expectancy of the well. A well to be converted to a saltwater disposal well must have surface casing set and cemented at a point not less than fifty feet [15.24 meters] below the base of the Fox Hills formation. In determining and specifying casing and cementing requirements, all of the following factors shall be considered:

a.Depth to the injection zone and lower confining zone. Long string casing must be set at least to the top of the injection zone and cemented at least to the top of the upper confining zone, or to a point approved by the director.

b.Depth to the bottom of all underground sources of drinking water.

c.Estimated maximum and average injection pressures.

d.Fluid pressure.

e.Estimated fracture pressure.

f.Physical and chemical characteristics of the injection zone.

2.Appropriate logs and other tests shall be conducted during the drilling and construction of injection wells. Any well drilled or converted to an injection well shall have a log run from which the quality of the cement bond can be determined. Cement bond logs shall contain at least the following elements: a gamma ray curve; a casing collar locator curve; a transit time curve; an amplitude curve; and a variable density curve. A descriptive report interpreting the results of these logs and tests shall be prepared by a qualified log analyst and submitted to the commission if deemed necessary by the director.

3.All injection wells must be equipped with injection tubing and a packer set in the long string casing within one hundred feet measured depth of the top perforation, or at a depth approved by the director.

4.After an injection well has been completed, approval must be obtained on a sundry notice (form 4) or form provided by the director prior to any subsequent perforating.

5.Surface facilities must be constructed pursuant to sections 43-02-03-53, 43-02-03-53.1, 43-02-03-53.2, and 43-02-03-53.3.

January 1, 2006; April 1, 2018; April 1, 2020.

History

• History: Effective November 1, 1982; amended effective May 1, 1992; July 1, 1996; May 1, 2004;

N.D. Admin. Code 43-02-05-07 Mechanical integrity

1.Prior to commencing operations, the operator of a new injection well must demonstrate the mechanical integrity of the well. Prior to performing any workover project on an existing well, during which the packer or other means of annular isolation could be affected, the operator shall obtain approval from the director. All existing injection wells must demonstrate continual mechanical integrity and be tested at least once every five years. Following the completion of any remedial work, the operator shall demonstrate the mechanical integrity of the well. The director may require further mechanical integrity tests or other remedial work to ensure the mechanical integrity of the well to prevent the movement of fluid into an underground source of drinking water or an unauthorized zone. Mechanical integrity pressure tests must be performed at one thousand pounds per square inch [6900 kilopascals] for a minimum of fifteen minutes. A mechanical integrity test pressure of less than one thousand pounds per square inch [6900 kilopascals] may be approved by the director. Once an injection well is determined to lack mechanical integrity, within ninety days of the determination, it must be repaired and retested or plugged and abandoned.

An injection well has mechanical integrity if:

a.There is no significant leak in the casing, tubing, or packer; and

b.There is no significant fluid movement into an underground source of drinking water or an unauthorized zone through vertical channels adjacent to the injection bore.

2.One of the following methods must be used to evaluate the absence of significant leaks:

a.Pressure test with liquid or gas.

b.Monitoring of positive annulus pressure following a valid pressure test.

c.Radioactive tracer survey.

3.One of the following methods must be used to establish the absence of significant fluid movement:

a.A log from which cement can be determined or well records demonstrating the presence of adequate cement to prevent such migration.

b.Radioactive tracer survey, temperature log, or noise log.

4.The operator of an injection well immediately shall shut-in the well if mechanical failure indicates fluids are, or may be, migrating into an underground source of drinking water or an unauthorized zone, or if so directed by the director.

October 1, 2016; April 1, 2020.

History

• History: Effective November 1, 1982; amended effective May 1, 1990; July 1, 1996; May 1, 2004;

N.D. Admin. Code 43-02-05-08 Plugging of injection wells

The proper plugging of an injection well requires the well be plugged with cement or other types of plugs, or both, in a manner which will not allow movement of fluids into an underground source of drinking water. The operator shall file a notice of intention to plug (form 4) or form provided by the director and shall obtain the director's approval of the plugging method prior to the commencement of plugging operations.

History

• History: Effective November 1, 1982; amended effective May 1, 1992; May 1, 1994; April 1, 2020.

N.D. Admin. Code 43-02-05-09 Pressure limitations

Injection pressure at the wellhead shall not exceed a maximum authorized injection pressure which shall be calculated so as to assure that the pressure in the injection zone during injection does not initiate new fracture or propagate existing fractures in the confining zones. In no case shall injection pressure initiate fractures in the confining zones or cause the movement of injection or formation fluids into an unauthorized zone or underground source of drinking water.

History

• History: Effective November 1, 1982; amended effective May 1, 1992; April 1, 2018; April 1, 2020.

N.D. Admin. Code 43-02-05-10 Corrective action

If any monitoring indicates the movement of injection or formation fluids into an unauthorized zone or underground sources of drinking water, the director shall prescribe such additional requirements for construction, corrective action, operation, monitoring, or reporting as are necessary to prevent such movement.

History

• History: Effective November 1, 1982; amended effective April 1, 2020.

N.D. Admin. Code 43-02-05-11 Bonding requirements

All injection wells must be bonded as provided in section 43-02-03-15. A commercial injection well is one that only receives fluids produced from wells operated by a person other than the principal on the bond.

History

• History: Effective November 1, 1982; amended effective May 1, 1992; July 1, 2002; October 1, 2016.

N.D. Admin. Code 43-02-05-12 Reporting, monitoring, and operating requirements

1.The operator of an injection well shall meter or use an approved method to keep records and shall report monthly to the director, the volume and nature, i.e., produced water, pit water, makeup water, etc., of the fluid injected, the average operating and maximum injection pressures, the maximum injection rate, and such other information as the director may require. The operator of each injection well shall, on or before the fifth day of the second month succeeding the month in which the well is capable of injection, file with the director the aforementioned information for each well in a format provided by the director.

2.Immediately upon the commencement or recommencement of injection, the operator shall notify the director of the injection date verbally and in writing.

3.The operator shall place accurate gauges on the tubing and the tubing-casing annulus.

Accurate gauges shall also be placed on any other annuluses deemed necessary by the director.

4.The operator of an injection well shall keep the well, surface facilities, and injection system under continuing surveillance and conduct such monitoring, testing, and sampling as the director may require to verify the integrity of the surface facility, gathering system, and injection well to protect surface and subsurface waters. Prior to commencing operations, the saltwater disposal injection pipeline must be pressure tested. All existing saltwater disposal injection pipelines where the pump and the wellhead are not located on the same site are required to be pressure tested annually.

5.The operator of an injection well shall report any noncompliance with regulations or permit conditions to the director verbally within twenty-four hours followed by a written explanation within five days. The operator shall cease injection operations if so directed by the director.

6.Within ten days after the discontinuance of injection operations, the operator shall notify the director of the date of such discontinuance and the reason therefor.

7.Upon the completion or recompletion of an injection well or the completion of any remedial work or attempted remedial work such as plugging back, deepening, acidizing, shooting, formation fracturing, squeezing operations, setting liner, perforating, reperforating, tubing repairs, packer repairs, casing repairs, or other similar operations not specifically covered herein, a report on the operation shall be filed with the director within thirty days. The report shall present a detailed account of all work done, including the reason for the work, the date of such work, the shots per foot and size and depth of perforations, the quantity of sand, crude, chemical, or other materials employed in the operation, the size and type of tubing, the type and location of packer, the result of the packer pressure test, and any other pertinent information or operations which affect the status of the well and are not specifically covered herein.

8.Annular injection of fluids is prohibited.

May 1, 2004; April 1, 2018; April 1, 2020.

History

• History: Effective November 1, 1982; amended effective May 1, 1992; May 1, 1994; July 1, 1996;

N.D. Admin. Code 43-02-05-13 Access to records

The industrial commission and the director shall have access to all injection well records wherever located. All owners, operators, drilling contractors, drillers, service companies, or other persons engaged in drilling, completing, operating, or servicing injection wells shall permit the industrial commission, or the director, to come upon any lease, property, well, or drilling rig operated or controlled by them, complying with state safety rules and to inspect the records and operation of wells and to conduct sampling and testing. Any information so obtained shall be public information. If requested, copies of injection well records must be filed with the commission or director.

All owners, operators, drilling contractors, drillers, service companies, or other persons engaged in drilling, completing, operating, or servicing injection wells shall make and keep appropriate books and records for a period of not less than six years, covering their operations in North Dakota from which they may be able to make and substantiate the reports required by this chapter.

History

• History: Effective November 1, 1982; amended effective May 1, 1992; May 1, 1994; April 1, 2020. 43-02-05-13.1. Books and records to be kept to substantiate reports.
• History: Effective September 1, 2000.
• General Authority: NDCC 38-08-04
• Law Implemented: NDCC 38-08-04

N.D. Admin. Code 43-02-05-14 Area permits

1.The director, after notice and hearing, may issue an area permit providing for the permitting of individual injection wells if the proposed injection wells are:

a.Within the same field, facility site, reservoir, project, or similar unit in the same state;

b.Of similar construction;

c.Of the same class; and

d.Operated by a single owner or operator.

2.An area permit application shall include at least the following information:

a.The name and address of the operator.

b.A plat and maps depicting the area permit and one-quarter mile [402.34 meters] adjacent detailing the location of all anticipated injection wells and the location, well name, and operator of all producing wells, saltwater disposal wells, injection wells, plugged wells, abandoned wells, drilling wells, dry holes, permitted wells, water wells, surface bodies of water, and other pertinent surface features, such as occupied dwellings and roads.

c.A review of the surficial aquifers within the proposed area permit boundary and one mile adjacent.

d.Appropriate geological data on the injection zone and the upper and lower confining zones, including geologic names, lithologic descriptions, thicknesses, and depths.

e.Estimated fracture pressure of the upper confining zone.

f.Estimated maximum injection pressure.

g.Geologic name and depth to base of the lowermost underground source of drinking water which may be affected by the injection.

h.A reference well log, displaying at least a gamma ray curve, from a nearby well.

i.If faults are known or suspected, a cross section that includes a depiction of the fault at depth.

j.Proposed injection program, including method of transportation of the fluid to the injection facilities and wells.

k.List identifying all source wells or sources of injectate.

l.Quantitative analysis from a state-certified laboratory of a representative sample of water to be injected. A compatibility analysis with the receiving formation may also be required.

m.Legal description of the land ownership within and one-quarter mile [402.34 meters] adjacent to the proposed area permit in both tabular and plat form.

n.An affidavit of mailing, and proof of service, certifying that all landowners within the proposed area permit and one-quarter mile adjacent have been notified of the proposed area permit. A representative copy of the letters sent must be attached to the affidavit.

The notice must inform the landowners that a hearing will be held at which comments or objections may be directed to the commission, and that written comments or objections to the application may be submitted prior to the hearing date, received by the commission no later than five p.m. on the last business day prior to the hearing date.

o.Schematic of the proposed injection system, including facilities and pipelines.

p.A schematic drawing of a typical proposed injection well bore construction, including the size of the borehole; the total depth and plug back depth; the casings and tubing sizes, weights, grades, and top and bottom depths; the perforated interval top and bottom depths; the packer depth; the injection zone and upper and lower confining zones' top and bottom depths.

q.Any other information required by the director to evaluate the proposal.

3.An area permit authorizes the director to approve individual injection well permit applications within the permitted area. The application shall be made in a format provided by the director and shall include at least the following information:

a.The name and address of the operator of the injection well.

b.The surface and bottom hole location.

c.Average and maximum daily rate of fluids to be injected.

d.Existing or proposed casing, tubing, and packer data.

e.Existing or proposed cement specifications, including amounts and actual or proposed top.

f.A plat and maps depicting the area of review (one-quarter-mile [402.34-meter] radius) and detailing the location, well name, and operator of all wells in the area of review. The plat, maps, or both must include all producing wells, saltwater disposal wells, injection wells, abandoned wells, drilling wells, plugged wells, dry holes, permitted wells, water wells, surface bodies of water, and other pertinent surface features, such as occupied dwellings and roads.

g.A review of the surficial aquifers within one mile of the proposed injection well site or surface facilities.

h.A tabulation of data on all wells within the area of review which penetrate the proposed injection zone. Such data must include a description of each well's type, construction, date drilled, location, depth, record of plugging and completion, and any additional information the director may require. A detail of any corrective action necessary for any of the wells not properly cemented or plugged to prevent the movement of fluid out of the injection zone must also be included.

i.A tabulation of all freshwater wells and domestic freshwater sources within the area of review. Each freshwater well and domestic freshwater source must be identified by owner, location by quarter-quarter, section, township, and range, type of well or source, depth, and current status. A quantitative analysis from a state-certified laboratory of freshwater from the two nearest freshwater wells within a one-mile radius must be submitted. This requirement may be waived by the director in certain instances.

j.All logging and testing data on the well which has not been previously submitted.

k.A schematic drawing of the well detailing the proposed well bore construction, including the size of the borehole; the total depth and plug back depth; the casings and tubing sizes, weights, grades, and top and bottom depths; the perforated interval top and bottom depths; the packer depth; the injection zone and upper and lower confining zones' top and bottom depths.

l.A schematic or other appropriate drawings and tabulations of the wellhead and surface facilities, including the size, location, construction, and purpose of all tanks, the height and location of all dikes and containment, including a calculated containment volume, all areas underlain by a synthetic liner, the location of all flow lines, and a tabulation of any pressurized flow line specifications. It also must include the proposed road access to the nearest existing public road and the authority to build such access.

m.Traffic flow diagram of the site, depicting sufficient area to contain all anticipated traffic, if applicable.

n.A detailed drilling prognosis including a drilling, casing, cementing, logging, testing, and coring program, if applicable.

o.A detailed description of the proposed completion or conversion procedure.

p.Any additional information necessary to demonstrate that injection into the proposed injection zone will not initiate fractures in the confining zone that could allow fluid movement out of the injection zone.

q.Any other information required by the director to evaluate the proposed well.

4.The director is authorized to approve individual injection well permit applications within an area permit provided:

a.The additional well meets the area permit criteria.

b.The cumulative effects of drilling and operating additional injection wells are acceptable to the director.

5.If the director determines that any additional well does not meet the area permit requirements, the director may modify or terminate the permit or take enforcement action.

6.If the director determines the cumulative effects are unacceptable, the permit may be modified.

7.Area and individual injection well permits may contain such terms and conditions as the director deems necessary.

8.The corrective action plan for any well in the area of review which is not properly cemented or plugged to prevent the movement of fluid out of the injection zone must be incorporated into the permit as a condition if the plan is deemed adequate by the director. If the director deems the plan inadequate, the director shall require the applicant to revise the plan, prescribe a plan for corrective action as part of the permit, or deny the application. Before injection commences in an injection well, the applicant shall complete any needed corrective action on wells penetrating the injection zone in the area of review to the satisfaction of the director.

9.Any permit issued under this section may be revoked by the commission after notice and hearing if the permittee fails to comply with the terms and conditions of the permit or any applicable rule or statute. Any permit issued under this section may be suspended by the director for good cause.

10.Before a permit for underground injection will be issued, the applicant must satisfy the director that the proposed injection well will not endanger any underground source of drinking water.

11.No person shall commence construction of an underground injection well, site, or access road until the director has issued a permit for the well.

12.Area and individual injection well permits are transferable only with approval of the director.

13.Individual injection well permits may be modified by the director.

14.Individual injection well permits shall automatically expire one year after the date issued, unless operations have commenced to complete the well as an injection well.

15.If the permitted injection zone is plugged and abandoned, the permit shall expire and be of no further force and effect.

April 1, 2020.

History

• History: Effective November 1, 1982; amended effective May 1, 1992; May 1, 2004; January 1, 2006;

Chapter 43-02-06 Royalty Statements

N.D. Admin. Code 43-02-06-01 Royalty owner information statement

Whenever payment is made for oil or gas production to an interest owner, whether pursuant to a division order, lease, servitude, or other agreement, all of the following information must be included on the check stub or on an attachment to the form of payment, unless the information is otherwise provided on a regular monthly basis:

1.The lease, property, or well name or any lease, property, or well identification number used to identify the lease, property, or well; provided, that if a lease, property, or well identification number is used, the royalty owner must initially be provided the lease, property, or well name to which the lease, property, or well name refers.

2.The month and year during which sales occurred for which payment is being made.

3.One hundred percent of the corrected volume of oil, regardless of ownership, which is sold measured in barrels, and one hundred percent of the volume of either wet or dry gas, regardless of ownership, which is sold or removed from the premises for the purpose of sale, or sale of its contents and residue, measured in thousand cubic feet.

4.Price.

a.Oil. Weighted average price per barrel received by the producer for all oil sold during the period for which payment is made. The price must be the net price received by the producer after all deductions.

b.Gas and natural gas liquids. Weighted average price per thousand cubic feet [28.32 cubic meters] received by the producer for all gas sold and weighted average price per gallon received by the producer for all natural gas liquids sold during the period for which payment is made. The price must be the net price received by the producer after all deductions.

5.Total amount of state severance and other production taxes.

6.Producer's net value of total sales after taxes and deductions.

7.The amount and purpose of each owner deduction made, identified as transportation, processing, compression, or administrative costs.

8.The amount and purpose of each owner adjustment or correction made.

9.Owner's interest in sales from the lease, property, or well expressed as a decimal.

10.Owner's share of the total value of sales prior to removing any taxes. The value can be calculated before or after removing owner's deductions if it is clearly noted on the royalty statement or included on an attachment to the royalty statement.

11.Owner's share of sales value less taxes and deductions.

12.An address where additional information may be obtained and any questions answered. If information is requested by certified mail, the answer must be mailed by certified mail within thirty days of receipt of the request.

Within one hundred twenty days after the end of the month of the first sale of production from a well or change in the spacing unit of a well or a decimal interest in a mineral owner, the operator or payor shall provide the mineral owner with a statement identifying the spacing unit for the well, and the effective date of the spacing unit change or decimal interest change if applicable, the net mineral acres owned by the mineral owner, the gross mineral acres in the spacing unit, and the mineral owner's decimal interest that will be applied to the well.

History

• History: Effective November 1, 1983; amended effective April 1, 1984; November 1, 1987; May 1, 1992; April 1, 2018; April 1, 2020. 43-02-06-01.1. Ownership interest information statement.
• History: Effective April 1, 2018; amended effective April 1, 2020.

N.D. Admin. Code 43-02-06-02 Annual windfall profits tax information statement

Repealed effective May 1, 1992.

N.D. Admin. Code 43-02-06-03 Annual stored gas information statement

Any person required to submit information, as provided by this chapter, to a royalty owner shall, if gas either wholly or partially owned by a royalty owner is being placed into storage off the leased premises, provide the royalty owner with an annual statement containing the following information:

1.Total corrected volume of gas measured in standard thousand cubic feet (MCF) in storage at the beginning of the calendar year;

2.Total corrected volume of gas measured in thousand cubic feet added each month to storage during the calendar year;

3.Total corrected volume of gas measured in thousand cubic feet removed each month from storage during the calendar year; and

4.Total corrected volume of gas measured in thousand cubic feet in storage at the end of the calendar year.

The information required by this section must be supplied for all royalty owner gas placed into storage after December 31, 1986, and must be mailed to the royalty owner annually no later than March thirty-first immediately following each calendar year covered by the statement.

History

• History: Effective November 1, 1987; amended effective May 1, 1992.

N.D. Admin. Code 43-02-06-04 Books and records to be kept to substantiate reports

All operators shall make and keep appropriate books and records for a period of not less than six years, covering their operations in North Dakota from which they may be able to make and substantiate the reports required by this chapter.

History

• History: Effective September 1, 2000.

Chapter 43-02-07 Geothermal Energy Production

N.D. Admin. Code 43-02-07-01 Definitions

The terms used throughout this chapter have the same meaning as in North Dakota Century Code

chapter 38-19, except:

1."Closed-loop system" means any geothermal energy extraction facility, vertical, horizontal, or otherwise, in which a fluid is permanently confined within pipe or tubing and does not come in contact with the outside environment.

2."Commission" means the industrial commission of this state.

3."Contaminant" means any physical, chemical, biological, or radiological substance or matter in water.

4."Deep well" means any well drilled into rocks older than the greenhorn formation or which encounters brackish or saline formation waters to develop or produce geothermal energy.

5."Injection well" means a well into which fluids are being injected.

6."Open-loop system" means any geothermal energy extraction facility in which water is extracted for heating or cooling purposes and is reinjected into the subsurface or disposed of at the surface.

7."Person" means and includes any natural person, corporation, association, partnership, receiver, trustee, executor, administrator, guardian, fiduciary, or other representative of any kind and includes any department, agency or instrumentality of the state, or of any governmental subdivision thereof.

8."Shallow well" means any well drilled into rocks younger than the belle fourche formation and does not encounter saline or brackish formation waters to develop or produce geothermal energy.

9."Substantial modification" means the construction or installation of any addition, or any restoration or renovation, of a geothermal energy extraction facility which increases or decreases its heating or cooling capacity, significantly alters its physical configuration, or impairs or improves its physical integrity. In all cases, the determination of "substantial modification" must be made by the state geologist.

10."Underground source of drinking water" means an aquifer or its portion which supplies drinking water for human consumption or in which the ground water contains fewer than ten thousand milligrams per liter total dissolved solids.

11."Well" means a bored, drilled or driven shaft, or a dug hole, whose depth is greater than the largest surface dimension.

History

• History: Effective March 1, 1984; amended effective October 1, 1990; December 1, 1992.

N.D. Admin. Code 43-02-07-02 Scope of chapter

This chapter is of statewide application and has been adopted by the commission to conserve the natural resources of this state, to prevent waste, to protect the correlative rights of all owners, to prevent the contamination of underground sources of drinking water, and to avoid creation of secondary hazards of geologic nature. These rules do not apply to deep-well geothermal resources regulated under chapter 43-02-07.1. The commission may grant exceptions to this chapter, after due notice and hearing, when such exceptions will result in the prevention of waste and operation in a manner to protect correlative rights.

History

• History: Effective March 1, 1984; amended effective October 1, 2020.

N.D. Admin. Code 43-02-07-03 Powers and duties

The state geologist shall act as a supervisor charged with the duty of enforcing the regulations and orders of the commission applicable to geothermal energy extraction facilities. All applications, correspondence, protests, and other communications shall be addressed to the state geologist as follows:

State Geologist 600 East Boulevard Bismarck, ND 58505 (701) 328-8000

N.D. Admin. Code 43-02-07-04 Authority to cooperate with other agencies

The commission may from time to time enter into arrangements with state and federal agencies, industry, and individuals with respect to special projects, services, and studies relating to geothermal energy.

N.D. Admin. Code 43-02-07-05 Prohibition of movement of fluids into underground sources of drinking water

No producer may construct, operate, maintain, convert, plug, or abandon any geothermal energy extraction facility in a manner which causes or allows movement of fluid containing any contaminant into underground sources of drinking water or which may adversely affect human health. The applicant for a permit has the burden to prove that the requirements of this section are met.

N.D. Admin. Code 43-02-07-06 Permit required

A permit is required prior to the commencement of operations for the drilling, boring, excavating, or construction of a new geothermal energy extraction facility, or substantial modification of an existing geothermal energy extraction facility loop field. A permit is not required for facilities that use a treated municipal water supply as its sole source of water. A permit may be required by the state department of health or the water utility, or both, for facilities hooked into a municipal water supply. The state geologist may grant a permit upon receipt of a permit application on a form provided by the commission, the furnishing of a bond (if required) as provided in section 43-02-07-08, and the payment of a fee of one hundred dollars for each commercial facility permit or twenty dollars for each residential facility permit.

The state geologist may waive the fee requirement if the applicant is an instrumentality of the state. The application for a permit must be accompanied by an accurate plat showing the location of the proposed facility with reference to the nearest lines of a governmental section.

The state geologist may deny all or part of an application for permit if the construction of a geothermal energy extraction facility would violate correlative rights or would cause, or tend to cause, waste, damage to the environment, or contaminate underground sources of drinking water. The applicant may appeal the decision of the state geologist to the commission. The state geologist may add stipulations to the permit.

History

• History: Effective March 1, 1984; amended effective October 1, 1990; December 1, 1992; January 1, 2008; October 1, 2020.
• Law Implemented: NDCC 38-19-03, 38-19-04

N.D. Admin. Code 43-02-07-07 Modification or revocation and reissuance of permit - Termination of permit - Transfer or renewal of permit

1.Modification or revocation and reissuance of permit.

a.The commission may modify or revoke and reissue a permit if there are substantial alterations or additions to the permitted facility, or if the standards or regulations on which the permit was based have been changed by promulgation of amended standards or regulations or by judicial decision after the permit was issued.

b.When a permit is modified, only the conditions subject to modification are reviewed. If a permit is revoked and reissued, the entire permit is reviewed and subject to revision and the permit is reissued for a new term.

2.Termination of permit.

a.The commission may terminate a permit during its term or deny a renewal application for noncompliance by the permittee with any condition of the permit, the rules or regulations, or failure to disclose fully or misrepresent all relevant facts.

b.A permit may be terminated if the permitted activity endangers human health or the environment, or causes pollution to underground sources of drinking water.

3.Transfer or renewal of permit.

a.A permit may be renewed or transferred to a new owner or operator if the current permittee notifies the commission at least thirty days in advance of the proposed renewal or transfer date and provided the permit does not need to be modified or revoked and reissued.

b.A notice of transfer must include a written agreement between the existing and new permittees containing a specific date for transfer of permit responsibility, coverage, and liability between them. The notice must demonstrate that the financial responsibility requirements of section 43-02-07-09 will be met by the new permittee.

History

• Law Implemented: NDCC 38-19-03, 38-19-04

N.D. Admin. Code 43-02-07-08 Bond

Before any person receives a permit to drill, bore, excavate, or construct a geothermal energy extraction facility, the person shall submit to the commission and obtain its approval of a surety bond or cash bond. An alternate form of security may be approved by the commission after notice and hearing, as provided by law. At the discretion of the state geologist, an installation or facility bond may be required for the substantial modification of a geothermal energy extraction facility in existence prior to December 1, 1992. The state geologist has the discretion to waive the requirement for a facility bond if the applicant is an instrumentality of the state. Each such bond must be executed by a responsible surety company authorized to transact business in this state.

The amount and type of the bond is as follows:

Shallow-well and horizontal-loop facilities.

1.The state geologist has the discretion to require a facility bond in the amount of fifteen thousand dollars for any geothermal energy extraction facility that, for any reason, constitutes a special threat to important ground water resources or the environment, or otherwise poses a significant public health hazard.

2.An installation bond in the amount of ten thousand dollars is required of installers of all geothermal energy extraction. This is a blanket bond and must cover all permits for geothermal energy extraction facilities issued in one year commencing on the date the first permit covered by the bond is issued. Alternately, at the discretion of the state geologist, an installation bond in the amount of one hundred dollars for each well or horizontal loop installed per year may be submitted.

3.The geothermal system installer must comply with North Dakota Century Code chapter 38-19 and all rules and orders of the commission as a condition of the installer's bond. Any violation of either North Dakota Century Code chapter 38-19 or the rules or orders of the commission makes the installer liable under the bond and the bond shall be subject to immediate forfeiture. The installer remains liable under the installation bond until construction of the geothermal energy extraction facility has been completed and the work has been approved by the state geologist. At the discretion of the state geologist, the installer's liability under the bond may be terminated at an earlier date when it can be demonstrated that only minor interior work remains to be completed and when completion of this work is subject to inordinate delays beyond the control of the geothermal system installer.

The owner of a geothermal energy extraction facility is responsible for obtaining the facility bond in subsection 1.

The owner of the geothermal energy extraction facility who is required to obtain a facility bond under subsection 1 must comply with North Dakota Century Code chapter 38-19 and all rules and orders of the commission as a condition of the owner's bond. Any violation of either North Dakota Century Code chapter 38-19 or the rules or orders of the commission makes the owner liable under the facility bond, and the bond shall be subject to immediate forfeiture. The owner of the geothermal energy extraction facility remains liable under the bond until either of the following occurs: (1) the wells or loop systems have been satisfactorily plugged as provided in this chapter, the sites disturbed by any method of production of geothermal energy have been reclaimed in a manner approved by the state geologist, and all logs, plugging records, and other pertinent data required by statute or rules and orders of the commission are filed and approved; or (2) the liability on the bond has been transferred to another bond and such transfer approved by the commission.

The commission shall advise the surety and the principal when liability on a surety bond is terminated.

The state geologist is authorized to act for the commission as to all matters within this section.

History

• History: Effective March 1, 1984; amended effective October 1, 1990; December 1, 1992; April 1, 1994; May 1, 1994; May 1, 2004; October 1, 2020.

N.D. Admin. Code 43-02-07-09 Proof of financial responsibility

The permittee shall maintain financial responsibility and resources to close, plug, and abandon the geothermal energy extraction facility according to this chapter. The permittee shall show evidence of financial responsibility to the commission by the submission of surety bond, or other adequate assurance, such as financial statements or other materials acceptable to the commission.

History

• History: Effective March 1, 1984.

N.D. Admin. Code 43-02-07-10 Technical requirements

All wells must be made by a certified water or monitoring well contractor. All open-loop geothermal energy extraction facility wells must be in compliance with article 33-18. The location and construction of the borehole of closed-loop geothermal energy extraction facilities must be in compliance with article 33-18.

All geothermal energy extraction facilities, including horizontal-loop facilities, must be approved by the state geologist prior to installation.

All heat transfer fluids and additives must be approved for use by the state geologist.

History

• History: Effective March 1, 1984; amended effective December 1, 1992.

N.D. Admin. Code 43-02-07-11 Completion report and basic data collected

Within thirty days after the completion of any geothermal energy extraction facility, a completion report must be filed with the state geologist, on a form prescribed by the commission.

The following basic data developed by the producer must be delivered, free of charge, to the state geologist, if requested, within six months of the filing of the completion report:

1.Washed and packaged sample cuts, core chips, or whole cores minus those portions of cores used for necessary testing or analysis in which case the results of testing, the analysis, and the description of missing portions shall be submitted to the state geologist upon request.

Sample cuttings must be packaged in standard sample envelopes which in turn must be placed in proper order in a standard sample box and carefully identified as to producer, well location, and depth of sample.

2.Sample logs, radioactivity logs, resistivity logs, or other types of electrical or mechanical logs.

3.Elevation and location information on the data collection points.

4.Other pertinent information as may be requested by the state geologist.

N.D. Admin. Code 43-02-07-12 Production reports

The producer of each and every open-loop geothermal energy extraction facility shall on or before the first day of February of each year file with the state geologist a sworn statement showing the quantities, temperatures, and nature of products extracted from or by means of any facility during the month and the ultimate disposition of such products.

History

• History: Effective March 1, 1984; amended effective October 1, 1990; December 1, 1992.

N.D. Admin. Code 43-02-07-13 Records to be kept

All producers of geothermal energy within this state shall make and keep appropriate books and records for a period not less than ten years, from which they may be able to make and substantiate the reports required by this chapter.

N.D. Admin. Code 43-02-07-14 Disposal of unusable products

The surface disposal or underground injection of unusable products or waste produced from a geothermal energy extraction facility must satisfy additional state laws and regulations. The state department of health must be notified of the disposal method and may require a permit under North Dakota Century Code chapter 61-28 or North Dakota Administrative Code article 33.1-25.

History

• History: Effective March 1, 1984; amended effective October 1, 2020.

N.D. Admin. Code 43-02-07-15 Plugging and abandonment

Notice of intention to abandon any geothermal energy extraction facility must be filed with the state geologist by the producer prior to the commencement of plugging operations, on a form prescribed by the state geologist. The notice must state the name and location of the well or well field and the name of the producer.

Before any geothermal energy extraction facility is abandoned, it must be plugged in a manner which will confine permanently all subsurface minerals, oil, gas, and water in the separate strata originally containing them. This operation must be accomplished by the use of mud-laden fluid, cement, and plugs, used singly or in combination as may be approved by the state geologist. Casing must be cut off three feet [.91 meters] below the surface of the ground. The top plug in any hole must be set at least three feet [.91 meters] below ground level, and the land surface must be restored as nearly as possible to its original condition.

Shallow closed-loop systems using an approved heat transfer fluid may, upon approval of the state geologist, be abandoned by permanently sealing all of the loop ends and burying all pipes at least three feet [.91 meters] below ground. Closed-loop systems must be completely purged of heat transfer fluid prior to plugging. This fluid must be disposed of in accordance with the provisions of North Dakota Century Code chapter 61-28 and other state laws and regulations.

History

• History: Effective March 1, 1984; amended effective October 1, 1990; December 1, 1992; January 1, 2008.

Chapter 43-02-07.1 Deep Geothermal Energy Production

N.D. Admin. Code 43-02-07.1 Deep Geothermal Energy Production

CHAPTER 43-02-07.1

DEEP GEOTHERMAL ENERGY PRODUCTION

Section 43-02-07.1-01Definitions 43-02-07.1-02Scope of Chapter 43-02-07.1-03Enforcement of Laws, Rules, and Regulations Dealing With Conservation, Exploration, and Development of Deep-well Geothermal Resources 43-02-07.1-04Waste Prohibited 43-02-07.1-05United States Government Leases 43-02-07.1-06Forms Upon Request 43-02-07.1-07Authority to Cooperate With Other Agencies 43-02-07.1-08Organization Reports 43-02-07.1-09Reservoir Surveys 43-02-07.1-10Access to Sites and Records 43-02-07.1-11Exploration Well Bond 43-02-07.1-12Facility Bond 43-02-07.1-13Exploration Permit 43-02-07.1-14Facility Permit 43-02-07.1-15Notice and Hearing 43-02-07.1-16Approval or Denial of Permit Application 43-02-07.1-17Operators of Class V Injection Wells 43-02-07.1-18Geologic Data 43-02-07.1-19Report of Production and Injection 43-02-07.1-20Measurement of Rate of Flow of Water and Steam and of Pressure and Temperature of Fluids 43-02-07.1-21Additional Information May Be Required 43-02-07.1-22Books and Records to Be Kept to Substantiate Reports 43-02-07.1-23Disposal of Waste Material 43-02-07.1-24Facility Annual Operating Fee 43-02-07.1-25Reclamation of Exploration Wells 43-02-07.1-26Reclamation of Facilities 43-02-07.1-27Hearings - Complaint Proceedings - Emergency Proceedings - Other Proceedings 43-02-07.1-28Investigatory Hearings 43-02-07.1-29Official Record 43-02-07.1-30Petitions for Review of Recommended Order and Oral Arguments Prohibited 43-02-07.1-31Notice of Order by Mail 43-02-07.1-32Service and Filing 43-02-07.1-33Designation of Examiners 43-02-07.1-34Powers and Duties of Examiner 43-02-07.1-35Report of Examiner 43-02-07.1-36Commission Order From Examiner Hearing 43-02-07.1-37Prehearing Motion Practice 43-02-07.1-01. Definitions.

The terms used throughout this chapter have the same meaning as in North Dakota Century Code chapters 38-08 and 38-19 except:

1."Certified or registered mail" means any form of service by the United States postal service, federal express, Pitney Bowes, and any other commercial, nationwide delivery service that provides the mailer with a document showing the date of delivery or refusal to accept delivery.

2."Contaminant" means any physical, chemical, biological, or radiological substance or matter in water.

3."Deep geothermal well" means any well drilled into rocks older than the Greenhorn Formation which encounters hot water or hot brines to develop or produce energy from deep-well geothermal resources.

4."Facility" includes all surface structures (buildings, slabs or pads, pipelines, etc.) for the production of energy from deep-well geothermal resources as well as all subsurface structures, including deep geothermal and injection wells.

5."Injection well" means a well into which fluids resulting from the development or production of energy from deep-well geothermal resources are being injected.

6."Occupied dwelling" or "permanently occupied dwelling" means a residence that is lived in by a person at least six months throughout a calendar year.

8."Pool" means an underground reservoir containing a common accumulation of geothermal energy; each zone of a structure that is completely separated from any other zone in the same structure is a pool, as that term is used in this chapter.

9."Underground source of drinking water" means an aquifer or its portion that supplies drinking water for human consumption or in which the ground water contains fewer than ten thousand milligrams per liter total dissolved solids.

10."Well" means a bored, drilled or driven shaft, or a dug hole, whose depth is greater than the largest surface dimension. 43-02-07.1-02. Scope of chapter.

This chapter contains general rules of statewide application which have been adopted by the industrial commission to conserve the natural resources of North Dakota, to prevent waste, and to provide for operation in a manner as to protect correlative rights of all owners of deep-well geothermal resources. These rules do not apply to geothermal resource wells regulated under chapter 43-02-07 which are used for the purpose of heating and cooling in ground- or water-source heat pump systems.

The commission may grant exceptions to this chapter, after due notice and hearing, when such exceptions will result in the prevention of waste and operate in a manner to protect correlative rights. 43-02-07.1-03. Enforcement of laws, rules, and regulations dealing with conservation, exploration, and development of deep-well geothermal resources.

The commission, its agents, representatives, and employees are charged with the duty and obligation of enforcing all rules and statutes of North Dakota relating to geothermal resources.

However, it is the responsibility of all owners, operators, and contractors to obtain information pertaining to the regulation of geothermal resources before operations have begun. 43-02-07.1-04. Waste prohibited.

All operators, contractors, drillers, carriers, service companies, and all other persons shall at all times conduct their operations in the drilling, equipping, operating, producing, plugging, and site reclamation of a geothermal energy extraction facility in a manner that will prevent waste and the movement of fluid containing any contaminant into underground sources of drinking water or which may adversely affect human health. 43-02-07.1-05. United States government leases.

The commission recognizes that all persons drilling and producing on United States government land shall comply with the United States government regulations. Such persons also shall comply with all applicable state rules and regulations. Copies of the sundry notices, reports on wells, and well data required by this chapter of the wells on United States government land must be furnished to the commission at no expense to the commission. Federal forms may be used when filing such notices and reports except for reporting the plugging and abandonment of a well. In such instance, the plugging record must be filed on a form approved by the commission. 43-02-07.1-06. Forms upon request.

Forms for written notices, requests, and reports required by the commission must be furnished upon request. These forms must be of such nature as prescribed by the commission to cover proposed work and to report the results of completed work. 43-02-07.1-07. Authority to cooperate with other agencies.

The commission may from time to time enter arrangements with state and federal agencies, industry, and individuals with respect to special projects, services, and studies relating to geothermal energy. 43-02-07.1-08. Organization reports.

Every person acting as principal or agent for another or independently engaged in the drilling of deep geothermal wells, or in the exploration, production, reclaiming, treating, and disposal of geothermal resources in North Dakota immediately shall file with the state geologist the name under which such business is being conducted or operated; and name and post office address of such person, the business or businesses in which the person is engaged; the plan of organization, and in case of a corporation, the law under which it is chartered; and the names and post office addresses of any person acting as trustee, together with the names and post office addresses of any officials thereof on an organization report on a form approved by the commission. In each case in which such business is conducted under an assumed name, such organization report shall show the names and post office addresses of all owners in addition to the other information required. A new organization report must be filed when and if there is a change in any of the information contained in the original report. 43-02-07.1-09. Reservoir surveys.

By special order of the commission, periodic surveys may be made of the reservoirs in this state containing geothermal resources. These surveys must be thorough and complete and must be made using methods approved by the director. The condition of the reservoirs containing geothermal resources and the practices and methods employed by the operators must be investigated.

All operators of deep geothermal and injection wells shall permit and assist the agents of the commission in making any and all special tests that may be required by the commission on any or all wells.

All geophysical operations must comply with North Dakota Century Code chapter 38-08.1. 43-02-07.1-10. Access to sites and records.

The commission, director, and their representatives shall have access to all records wherever located. All owners, operators, drilling contractors, drillers, service companies, or other persons engaged in drilling, completing, producing, operation, or servicing wells or constructing, servicing, and maintaining facilities shall permit the commission, director, and their representatives to come upon any property, well, or drilling rig operated or controlled by them, complying with state safety rules, and to inspect the records and operation, and to have access at all times to any and all records. If requested, copies of such records must be filed with the commission. 43-02-07.1-11. Exploration well bond.

Before any person receives a permit to drill a well while exploring for geothermal resources, the person shall submit to the commission and obtain its approval of a surety bond or cash bond. An alternative form of security may be approved by the commission after notice and hearing, as provided by law. The operator of such well must be the principal on the bond covering the well. Each surety bond must be executed by a responsible surety company authorized to transact business in North Dakota.

The bond must be based upon the projected total depth of the well and the surface restoration costs.

Bonds must be conditioned upon full compliance with North Dakota Century Code chapter 38-19, and all administrative rules and orders of the commission. The well bonds eventually can be transferred to the facility bond if both are under the same operator. If the well operator and the facility operator are not one and the same, the well bonds continue until the well has been satisfactorily plugged, which must include practical reclamation of the well site and appurtenances; and all logs, plugging records, and other pertinent data required by statute or rules and orders of the commission are filed and approved.

Bond termination. The commission, in writing, shall advise the principal and any sureties on any bond as to whether the plugging and reclamation is approved. If approved, liability under such bond may be terminated formally upon receipt of a written request by the principal. The request must be signed by an officer of the principal or a person authorized to sign for the principal.

Director's authority. The director is vested with the power to act for the commission as to all matters within this section, except requests for alternative forms of security, which only may be approved by the commission. The commission may refuse to accept a bond if the operator or surety company has failed in the past to comply with statutes, rules, or orders relating to the operation of wells; if a civil or administrative action brought by the commission is pending against the operator or surety company; or for other good cause. 43-02-07.1-12. Facility bond.

Before any person receives a permit to construct a facility for the development or production of deep-well geothermal resources, the person shall submit to the commission and obtain its approval of a surety bond or cash bond. An alternative form of security may be approved by the commission after notice and hearing, as provided by law. The operator of such facility must be the principal on the bond covering the facility. The amount of the bond must be commensurate with the size and scope of the facility and the costs of abandoning the operation and reclamation. The information provided in section 43-02-07.1-14, along with any additional information available to the department, must be used to determine the amount of the bond. Each surety bond must be executed by a responsible surety company authorized to transact business in North Dakota. Bonds must be conditioned upon full compliance with North Dakota Century Code chapter 38-19, and all administrative rules and orders of the commission, and continue until the surface facility and all wells have been satisfactorily plugged and reclaimed and all logs, plugging records, and other pertinent data required by statute or rules and orders of the commission are filed and approved.

Bond termination. The commission, in writing, shall advise the principal and any sureties on any bond as to whether the plugging and reclamation is approved. If approved, liability under such bond may be terminated formally upon receipt of a written request by the principal. The request must be signed by an officer of the principal or a person authorized to sign for the principal.

Director's authority. The director is vested with the power to act for the commission as to all matters within this section, except requests for alternative forms of security, which only may be approved by the commission. The commission may refuse to accept a bond if the operator or surety company has failed in the past to comply with statutes, rules, or orders relating to the operation of wells; if a civil or administrative action brought by the commission is pending against the operator or surety company; or for other good cause.

The size and the scope of the operation must be evaluated annually and the department may increase or decrease the bond amount to reflect the results of the evaluation. 43-02-07.1-13. Exploration permit.

Before any person begins any well-site preparation for the drilling of any well other than surveying and staking for the purpose of exploring for deep-well geothermal resources, the person shall file an application for permit to drill on a form approved by the commission with the director, together with a permit fee of one hundred dollars. No drilling activity may commence until such application is approved and a permit to explore is issued by the director. The application must be accompanied by the bond pursuant to section 43-02-07.1-11 or the applicant previously must have filed such bond with the commission, otherwise the application is incomplete. An incomplete application received by the commission has no standing and may not be deemed filed until it is complete.

A permit is required for each test well. The application for permit to explore must be accompanied by an accurate plat certified by a registered surveyor showing the location of the proposed well with reference to true north and the nearest lines of a governmental section, the latitude and longitude of the proposed well location to the nearest tenth of a second, and the ground elevation. Information to be included in such application shall be the proposed depth to which the well will be drilled, estimated depth to the top of important stratigraphic markers, estimated depth to the top of objective horizons, the proposed mud program, the proposed casing program, including size and weight, the depth at which each casing string is to be set, the proposed pad layout, including cut and fill diagrams, and the proposed amount of cement to be used, including the estimated top of the cement, the proposed procedure, and the estimated completed total depth. The drilling, testing, and plugging of exploratory wells must comply with all applicable rules in chapter 43-02-03.

The exploration permit is in effect for one year. 43-02-07.1-14. Facility permit.

Before any person begins any site preparation for the construction of a deep-well geothermal facility, the person shall file an application for a facility permit on a form approved by the commission with the director, together with a permit fee. The amount of the permit fee to be determined by the state geologist based upon the cost for the commission to review, investigate, and process the application.

The department could take up to one hundred eighty days to review the permit application. No drilling activity may commence until such application is approved and a facility permit is issued by the director.

The application must be accompanied by the bond pursuant to section 43-02-07.1-12 or the applicant previously must have filed such bond with the commission, otherwise the application is incomplete. An incomplete application received by the commission has no standing and may not be deemed filed until it is complete.

Before any person begins any well-site preparation for the drilling of any well other than surveying and staking, the person shall file an application for a permit to drill on a form approved by the commission with the director, together with a permit fee of one hundred dollars. Verbal approval may be given for site preparation by the director in extenuating circumstances. No drilling activity may commence until such application is approved and a permit to drill is issued by the director. The application must be accompanied by the bond or the applicant previously must have filed such bond with the commission, otherwise the application is incomplete. An incomplete application received by the commission has no standing and may not be deemed filed until it is completed.

A permit is required for each facility. The facility permit application must include:

1.A description of the facility to be permitted. The facility area must be outlined on the application and the permit must be valid in the area so outlined. The application for a facility permit must be accompanied by an accurate plat certified by a registered surveyor showing the location of the proposed facility and wells with reference to true north and the nearest lines of a governmental section, the latitude and longitude of the proposed well locations to the nearest tenth of a second, the ground elevation, and the proposed road access to the nearest existing public road.

2.A description of the proposed geothermal production and injection (disposal) formations that includes the following:

a.Regional and site-specific geology pertaining to the geothermal operation.

b.A discussion of the geothermal regime and geothermal gradient of the production formation.

c.A discussion of the bounding formations of the disposal formation that includes continuity and thickness, lithology, integrity, and containment features.

d.Reservoir hydrogeology of the proposed production and disposal formations.

3.A description of the chemical and physical properties of the geothermal production and disposal formation waters that includes:

a.Water quality (density, chemical constituents, total dissolved solids, and other relevant data).

b.A discussion of the compatibility of the disposal fluids with the disposal formation.

4.The proposed depth to which the deep geothermal and injection wells will be drilled; estimated depth to the top of important stratigraphic markers; estimated depth to the top of objective horizons; the proposed mud program; the proposed casing program, including size and weight; the depth at which each casing string is to be set; the proposed pad layout, including cut and fill diagrams; and the proposed amount of cement to be used, including the estimated top of the cement, the proposed procedure, and the estimated completed total depth. The drilling, testing, disposal, and plugging of deep geothermal and injection wells will comply with all applicable rules in chapter 43-02-03.

5.A detailed description of the mechanical construction and operating procedures of the facility.

6.A justification of the need for the facility to be permitted, including economic impact.

7.A detailed discussion and description of a monitoring system to be used to ascertain the integrity of the facility and to ensure compliance with this chapter.

8.A detailed discussion and description of a reclamation program for the restoration of the surface as nearly as possible to its original condition and productivity upon expiration of the permit or termination of any activities regulated by this chapter.

9.Architectural plans for all buildings and infrastructure within the facility boundaries.

10.Any other information required by the commission.

The commission shall review the facility permit at least once every five years to determine whether it should be amended, modified, or revoked. 43-02-07.1-15. Notice and hearing.

The commission may require notice and hearing before a permit application is approved or denied.

Except in the case of an emergency, the commission shall give thirty days' notice to the general public of the time and place of the hearing on the application. Immediately upon receiving notice of the hearing date, the permit applicant shall give notice by certified mail to surface and subsurface owners within the permit application area and to the county recorder in the county or counties in which the proposed permit area is located.

General Authority: NDCC 38-19-04, 38-19-05

Law Implemented: NDCC 38-19-04, 38-19-05 43-02-07.1-16. Approval or denial of permit application.

The commission may approve the permit application as submitted, approve with conditions that ensure the protection of human health and the environment, or deny the application.

The commission may deny a permit application if the exploration, drilling, or operation poses a threat to human health or the environment, failure to meet the requirements set forth by the Century Code or administrative code, or for any other reason allowable by law. 43-02-07.1-17. Operators of class V injection wells.

Prior to the construction of any injection well to be utilized for the disposal of fluids resulting from deep geothermal energy production, the department of environmental quality shall permit an operator to operate the underground injection well pursuant to article 33.1-25.

All underground injection wells also are subject to chapter 43-02-03 where applicable. 43-02-07.1-18. Geologic data.

The following basic data collected by the operator must be delivered, free of charge, to the state geologist within thirty days of collection:

1.Washed and packaged sample cuts.

2.Cores, except those portions used for necessary testing or analysis, in which case the results of the testing, the analysis, and the description of missing portions shall be submitted to the state geologist.

3.Copies of all logs, including sample logs, radioactivity logs, resistivity logs, and other types of electrical or mechanical logs.

4.Elevation and location information on the data collection points.

5.Other pertinent information required by the state geologist. 43-02-07.1-19. Report of production and injection.

The operator of each deep geothermal well completed in any pool, on or before the first day of the second month succeeding the month in which production occurs, shall file a report with the state geologist showing the amount and temperature of production made by each such well upon form approved by the commission. The report must be signed by both the person responsible for the report and the person witnessing the signature. The printed name and title of both the person signing the report and the person witnessing the signature must be included.

The operator of each and every injection well, on or before the first day of the second month succeeding the month in which injection occurs, shall file a report with the state geologist showing the amount and composition of fluid injected upon a form approved by the commission. The report must be signed by both the person responsible for the report and the person witnessing the signature. The printed name and title of both the person signing the report and the person witnessing the signature must be included. 43-02-07.1-20. Measurement of rate of flow of water and steam and of pressure and temperature of fluids.

The rate of the flow of water or steam, or both, and the pressure and temperature of the fluids from each deep geothermal well must be accurately measured. Metering must be on a continuous basis and each well must be gauged at the frequency prescribed by the state geologist. 43-02-07.1-21. Additional information may be required.

This chapter may not be taken or construed to limit or restrict the authority of the commission to require the furnishing of such additional reports, data, or other information relative to production or products as may appear to be necessary or desirable, either generally or specifically, for the prevention of waste, protection of correlative rights, and the conservation of natural resources. 43-02-07.1-22. Books and records to be kept to substantiate reports.

All operators within North Dakota shall make and keep appropriate books and records for a period not less than six years covering their operations in North Dakota from which they may be able to make and substantiate the reports required by this chapter. 43-02-07.1-23. Disposal of waste material.

All waste material associated with exploration or production of geothermal energy must be properly disposed of in an authorized facility in accordance with all applicable local, state, and federal laws and regulations.

All waste material recovered from spills, leaks, and other such events immediately must be disposed of in an authorized facility, although the remediation of such material may be allowed onsite if approved by the state geologist. 43-02-07.1-24. Facility annual operating fee.

The annual operating fee must be based upon the costs to monitor and inspect the facility. 43-02-07.1-25. Reclamation of exploration wells.

The plugging and reclamation of exploration wells to comply with all applicable rules in chapter 43-02-03, including plugging and site reclamation. All lands disturbed during exploration for geothermal resources are to be reclaimed to a condition consistent with prior land use and productive capacity. 43-02-07.1-26. Reclamation of facilities.

The plugging and reclamation of all wells to comply with all applicable rules in chapter 43-02-03, including plugging and site reclamation. All buildings and infrastructure are to be removed. The site, access road, and other associated facilities constructed are to be reclaimed to a condition consistent with prior land use and productive capacity. 43-02-07.1-27. Hearings - Complaint proceedings - Emergency proceedings - Other proceedings.

1.Except as more specifically provided in North Dakota Century Code section 38-08-11, the rules of procedure established in subsection 1 of North Dakota Century Code section 28-32-21 apply to proceedings involving a complaint and a specific-named respondent.

2.For proceedings that do not involve a complaint and a specific-named respondent the commission shall give at least fifteen days' notice (except in emergency) of the time and place of hearing thereon by one publication of such notice in a newspaper of general circulation in Bismarck, North Dakota, and in a newspaper of general circulation in the county where the land affected or some part thereof is situated, unless in some particular proceeding a longer period of time or a different method of publication is required by law, in which event such period of time and method of publication shall prevail. The notice must be issued in the name of the commission and must conform to the other requirements provided by law.

3.In case an emergency is found to exist by the commission which in its judgment requires the making of a rule or order without first having a hearing, the emergency rule or order has the same validity as if a hearing with respect to the same had been held after notice. The emergency rule or order permitted by this section remains in force no longer than forty days from its effective date, and in any event, expires when the rule or order made after due notice and hearing with respect to the subject matter of such emergency rule or order becomes effective.

Any person moving for a continuance of a hearing and who is granted a continuance, shall submit a twenty-five dollar fee to the commission, or if the cost of republication exceeds fifty dollars the commission may bill the applicant to pay the cost of republication of notice of the hearing. 43-02-07.1-28. Investigatory hearings.

The commission may hold investigatory hearings upon the institution of a proceeding by application or by motion of the commission. Notice of the hearing must be served upon all parties personally or by certified mail at least five days before the hearing. 43-02-07.1-29. Official record.

The evidence in each case heard by the commission, unless specifically excluded by the hearing officer, includes the certified directional surveys, and all geothermal resource production records, and all injection records on file with the commission.

Any interested party may submit written comments on, or objections to, the application prior to the hearing date. Such submissions must be received no later than five p.m. on the last business day prior to the hearing date and may be part of the record in the case if allowed by the hearing examiner.

Settlement negotiations between parties to a contested case are only admissible as governed by North Dakota Century Code section 28-32-24, although the hearing officer may strike such testimony from the record for good cause. 43-02-07.1-30. Petitions for review of recommended order and oral arguments prohibited.

Neither petitions for review of a recommended order nor oral arguments following issuance of a recommended order and pending issuance of a final order are allowed. 43-02-07.1-31. Notice of order by mail.

The commission may give notice of an order by mailing the order, and findings and conclusions upon which it is based, to all parties by regular mail provided it files an affidavit of service by mail indicating upon whom the order was served. 43-02-07.1-32. Service and filing.

All pleadings, notices, written motions, requests, petitions, briefs, and correspondence to the commission or commission employee from a party (or vice versa) relating to a proceeding after its commencement, must be filed with the director and entered in the commission's official record of the procedure provided the record is open at the time of receipt. All parties must receive copies upon request of any or all of the evidence in the record of the proceedings. The commission may charge for the actual cost of providing copies of evidence in the record. Unless otherwise provided by law, filing is complete when the material is entered in the record of the proceeding. 43-02-07.1-33. Designation of examiners.

The commission by motion may designate and appoint qualified individuals to serve as examiners.

The commission may refer any matter or proceeding to any legally designated and appointed examiner or examiners. 43-02-07.1-34. Powers and duties of examiner.

The commission by motion may limit the powers and duties of any examiner in any particular case to such issues or to the performance of such acts as the commission deems expedient; however, subject only to such limitation as may be ordered by the commission, the examiner or examiners to whom any matter or proceeding is referred under this chapter have full authority to hold hearings on such matter or proceeding in accordance with and pursuant to this chapter. The examiner has the power to regulate all proceedings before the examiner and to perform all acts and take all measures necessary or proper for the efficient and orderly conduct of such hearing, including ruling on prehearing motions, the swearing of witnesses, receiving of testimony and exhibits offered in evidence, subject to such objections as may be imposed, and shall cause a complete record of the proceedings to be made and retained. 43-02-07.1-35. Report of examiner.

Upon conclusion of any hearing before an examiner, the examiner promptly shall consider the proceedings in such hearing, and based upon the record of such hearing, the examiner shall prepare a report and recommendations for the disposition of the matter or proceeding by the commission. Such report and recommendations either must be accompanied by a proposed order or must be in the form of a proposed order and must be submitted to the commission. 43-02-07.1-36. Commission order from examiner hearing.

After receipt of the report and recommendations of the examiner, the commission shall enter its order disposing of the matter or proceeding. 43-02-07.1-37. Prehearing motion practice.

In a matter pending before the commission, all prehearing motions must be served by the moving party upon all parties affected by the motion. Service must be upon a party unless a party is represented by an attorney, in which case service must be upon the attorney. Service must be made by delivering a copy of the motion and all supporting papers in conformance with one of the means of service provided for in Rule 5(b) of the North Dakota Rules of Civil Procedure. Proof of service must be made as provided in Rule 4 of the North Dakota Rules of Civil Procedure or by the certificate of an attorney showing that service has been made. Proof of service must accompany the filing of a motion.

Any motion filed without proof of service is not properly before the commission.

Chapter 43-02-08 Stripper Well and Stripper Well Property Determination

N.D. Admin. Code 43-02-08-01 Definitions

The terms used throughout this chapter have the same meaning as in chapter 43-02-03 and North Dakota Century Code chapters 38-08 and 57-51.1, except:

1."Commercial quantities" means production exceeding in value current operating costs.

2."Condensate recovered in nonassociated production" means a liquid hydrocarbon recovered from a well classified as a gas well by the commission.

3."Maximum efficient rate" means the maximum economic rate of production of oil which can be sustained under prudent operations, using sound engineering practices, without loss of ultimate recovery.

4."Operator" means any person who owns a fee interest or an interest in an oil and gas leasehold, and has the right to produce oil therefrom.

5."Qualifying period" means any preceding consecutive twelve-month period beginning after December 31, 1972, that the qualified maximum total production from a well or property did not exceed the production levels as specified in subsection 2 of section 43-02-08-03.

6."Well depth":

a.For a vertical or directional well means the lowest measured depth (measured in feet from the kelly bushing) producing from the pool during the qualifying period. In the event there is more than one vertical or directional well on a property producing from the same pool during the qualifying period, "well depth" means the average of the lowest measured depths producing from the pool of all vertical and directional wells in the property.

b.For a horizontal well means the measured depth of the terminus of the horizontal lateral (measured in feet from the kelly bushing) producing from the pool during the qualifying period. In the event there is more than one horizontal well on a property producing from the same pool during the qualifying period, "well depth" means the average measured depth of the termini of the horizontal laterals producing from the pool of all of the horizontal wells on the property.

April 1, 2014; April 1, 2024.

History

• History: Effective August 1, 1986; amended effective September 1, 1987; May 1, 1994; May 1, 2004;

N.D. Admin. Code 43-02-08-02 Application for stripper well or stripper well property determination

Any operator desiring to classify a well or property as a stripper well or a stripper well property for purposes of exempting production from the imposition of the oil extraction tax as provided under North Dakota Century Code chapter 57-51.1 shall file an application for stripper well or stripper well property determination with the director and obtain a determination certifying the well or property as a stripper well property. The applicant has the burden of establishing entitlement to stripper well or stripper well property status and shall submit all data necessary for a determination by the director.

The application must include the following:

1.The name and address of the applicant and the name and address of the person operating the well, if different.

2.The legal description of the well or property for which a determination is requested.

3.The well name and number and legal description of the oil-producing well or each oil-producing well on the property during the qualifying period and at the time of application.

4.The depth of all perforations (measured in feet from ground level) from the producing well or each producing well on the property during the qualifying period which produces from the same pool.

5.Designation of the well or property which the applicant requests to be certified as a stripper well or a stripper well property. Such designation must be accompanied by sufficient documentation for the director to determine (as set forth in section 43-02-08-02.1) that the well or property the applicant desires to be certified as a stripper well or a stripper well property constitutes a well or property as specified in North Dakota Century Code section 57-51.1-01.

6.The monthly production of the oil-producing well or each oil-producing well on the property during the qualifying period.

If the application does not contain sufficient information to make a determination, the director may require the applicant to submit additional information.

July 1, 1996; August 1, 1999; July 1, 2002; April 1, 2014; April 1, 2024. 43-02-08-02.1. Property determination.

The director recognizes the following as properties:

1.A unit.

2.A spacing unit.

3.Contiguous tracts within a lease.

4.A single well drilled and completed prior to July 1, 2013, is considered a single well stripper well property. A single well drilled and completed after June 30, 2013, is considered a single well stripper well.

Any well or portion of a property previously qualified as a stripper well property may not be redesignated to be included in another property unless approved by the commission after notice and hearing or unless such property lies within a unitized common source of supply.

All wells on the property must have been completed prior to July 1, 2013. A well completed after July 1, 2013, may not be added to an existing property.

October 1, 2016; April 1, 2024.

History

• History: Effective August 1, 1986; amended effective September 1, 1987; May 1, 1992; May 1, 1994;
• History: Effective September 1, 1987; amended effective May 1, 1992; May 1, 2004; April 1, 2014;

N.D. Admin. Code 43-02-08-03 Director shall determine stripper well or stripper well property status

1.Upon receipt of an application for stripper well or stripper well property determination, the director shall review the application, information, or comments submitted by any interested person and all relevant information contained in the books, files, and records of the commission.

2.Stripper well or stripper well property status must be determined on the basis of the qualified maximum total production of oil from the well or property. In order to qualify production from a well or property as maximum total production, the oil-producing well or each oil-producing well on the property must have been maintained at the maximum efficient rate of production or is not capable of exceeding the production thresholds below if the well or property had been maintained at the maximum efficient rate of production throughout the twelve-month qualifying period.

a.A property meets the requirements of a stripper well property if the qualified maximum total production of oil from the property excluding condensate did not exceed the following:

(1)Production from a well with a well depth of six thousand feet [1828.8 meters] or less did not exceed an average of ten barrels per day;

(2)Production from a well with a well depth of more than six thousand feet [1828.8 meters] but not more than ten thousand feet [3048.0 meters] did not exceed an average of fifteen barrels per day; or (3)Production from a well with a well depth of more than ten thousand feet [3048.0 meters] did not exceed an average of thirty barrels per day.

b.A well meets the requirements of a stripper well if the qualified maximum total production of oil from the well, excluding condensate, did not exceed the following:

(1)Production from a well with a well depth of six thousand feet [1828.8 meters] or less did not exceed an average of ten barrels per day;

(2)Production from a well with a well depth of more than six thousand feet [1828.8 meters] but not more than ten thousand feet [3048.0 meters] did not exceed an average of fifteen barrels per day;

(3)Production from a well outside the Bakken and Three Forks formations with a well depth of more than ten thousand feet [3048.0 meters] did not exceed an average of thirty barrels per day; or (4)Production from a well in the Bakken or Three Forks formations with a well depth of more than ten thousand feet [3048.0 meters] did not exceed an average of thirty-five barrels per day.

3.Within thirty days of the receipt of a complete application for stripper well or stripper well property status, or a reasonable time thereafter, the director shall either grant or deny the application.

4.If an application for stripper well or stripper well property status is denied, the director shall enter a written determination denying the application and specify the basis for the denial. If an application for stripper well or stripper well property status is granted, the director shall enter a written determination granting the application. A copy of the determination either granting or denying the application must be forwarded by the director by mail to the applicant and all other persons submitting comments. It is the obligation of the applicant to notify and advise the state tax commissioner, all other operators in the well or property, and the purchaser of the crude oil of the determination of the director.

May 1, 2004; April 1, 2014; October 1, 2016; April 1, 2024.

History

• History: Effective August 1, 1986; amended effective September 1, 1987; May 1, 1992; July 1, 1996;

N.D. Admin. Code 43-02-08-04 Applicant adversely affected may submit amended application - Procedure

Any applicant adversely affected by a determination of the director made under sections 43-02-08-02 through 43-02-08-03 may within thirty days after the entry of such a determination submit an amended application. If an amended application is submitted, the director shall issue a determination of stripper well or stripper well property status within thirty days of the receipt of the amended application or a reasonable time thereafter.

April 1, 2024.

History

• History: Effective August 1, 1986; amended effective September 1, 1987; May 1, 1992; April 1, 2014;

N.D. Admin. Code 43-02-08-05 Person adversely affected may petition the commission - Procedure

Any person adversely affected by a determination of the director of either an application or an amended application for stripper well or stripper well property status made under sections 43-02-08-02 through 43-02-08-03 may within thirty days after the entry of such a determination petition the commission for a hearing in accordance with the provisions of North Dakota Century Code chapter 38-08 and chapter 43-02-03.

April 1, 2024.

History

• History: Effective August 1, 1986; amended effective September 1, 1987; May 1, 1992; April 1, 2014;
• Law Implemented: NDCC 338-08-04(1)(d), 57-51.1-01

N.D. Admin. Code 43-02-08-06 Expiration date

Repealed effective September 1, 1987.

N.D. Admin. Code 43-02-08-07 Application to certify a qualifying secondary recovery project

N.D. Admin. Code 43-02-08-08 Commission certification of secondary recovery project

N.D. Admin. Code 43-02-08-09 Application to certify a qualifying tertiary recovery project

N.D. Admin. Code 43-02-08-10 Commission certification of tertiary recovery project

N.D. Admin. Code 43-02-08-11 Books and records to be kept to substantiate reports

Any operator desiring to classify a well or property as a stripper well property pursuant to this

chapter shall make and keep records for a period of not less than six years, covering their operations in North Dakota from which they may be able to make and substantiate the reports required by this

chapter.

History

• History: Effective September 1, 2000; amended effective April 1, 2014.
• General Authority: NDCC 38-08-04
• Law Implemented: NDCC 38-08-04

Chapter 43-02-09 Workover Projects [Repealed]

N.D. Admin. Code 43-02-09 Workover Projects [Repealed]

CHAPTER 43-02-09

WORKOVER PROJECTS [Repealed effective March 12, 2018]

Chapter 43-02-10 Certification of Secondary and Tertiary Recovery Projects - Determination of Incremental Production

N.D. Admin. Code 43-02-10-01 Definitions

The terms used throughout this chapter have the same meaning as in chapter 43-02-03 and North Dakota Century Code chapters 38-08 and 57-51.1 except:

1."New secondary recovery project" means a secondary recovery project which results in incremental production.

2."Normal production" means production from a unit obtained in the same manner and from the same wells which produce approximately the same amount of time.

History

• History: Effective May 1, 1992; amended effective May 1, 1994.
• Law Implemented: NDCC 57-51.1-03

N.D. Admin. Code 43-02-10-02 Application to certify a qualifying secondary recovery project

Any unit operator desiring to certify a secondary recovery project as a "qualifying secondary recovery project" for purposes of eligibility for the tax incentive provided in North Dakota Century Code

chapter 57-51.1 shall submit to the director an application for certification of a qualifying secondary recovery project. The unit operator has the burden of establishing entitlement to certification and shall submit all data necessary to enable the commission to determine whether the project is a qualifying secondary recovery project, and is entitled to the tax exemption provided in North Dakota Century Code section 57-51.1-03.

History

• History: Effective May 1, 1992; amended effective July 1, 1996; July 1, 2002; April 1, 2024.

N.D. Admin. Code 43-02-10-03 Commission certification of secondary recovery project

Upon the filing of an application for certification of a qualifying secondary recovery project, the commission shall promptly set a date for hearing. In determining whether a secondary recovery project shall be certified as a "qualifying secondary recovery project", the commission shall determine:

1.The amount of crude oil which would have been recovered from the unit source of supply if the secondary recovery project had not been commenced; and

2.Whether, for the purposes of a tax exemption and subsequent thereto the tax reduction, there has been incremental production.

History

• History: Effective May 1, 1992; amended effective April 1, 2024.

N.D. Admin. Code 43-02-10-04 Application to certify a qualifying tertiary recovery project

Any unit operator desiring to certify a tertiary recovery project as a "qualifying tertiary recovery project" for purposes of eligibility for the tax incentive provided in North Dakota Century Code chapter 57-51.1 shall submit to the director an application for certification of a qualifying tertiary recovery project. The unit operator has the burden of establishing entitlement to certification and shall submit all data necessary to enable the commission to determine whether the project is a qualifying tertiary recovery project, and is entitled to the tax exemption provided in North Dakota Century Code section 57-51.1-03.

History

• History: Effective May 1, 1992; amended effective July 1, 1996; July 1, 2002; April 1, 2024.

N.D. Admin. Code 43-02-10-05 Commission certification of tertiary recovery project

Upon the filing of an application for certification of a qualifying tertiary recovery project, the commission shall promptly set a date for hearing. In determining whether a tertiary recovery project shall be certified as a "qualifying tertiary recovery project", the commission shall determine:

1.Whether the tertiary recovery project meets the requirements of the tertiary recovery methods specified in subsection 6 of North Dakota Century Code section 57-51.1-01;

2.The amount of crude oil which would have been recovered from the unit source of supply if the tertiary recovery project had not been commenced;

3.Whether the tertiary recovery project has achieved for at least one month an average production level of at least fifteen percent above the amount of production which would have been recovered from the unit source of supply (as determined in subsection 2) if the tertiary recovery project had not been commenced; and

4.Whether, for the purposes of the tax exemption, there has been incremental production.

The commission shall, upon application or its own motion, have a hearing to determine whether the project operator continues to operate the unit as a qualifying tertiary recovery project.

History

• History: Effective May 1, 1992; amended effective September 1, 2000; April 1, 2024.
• Law Implemented: NDCC 38-08-04, 57-51.1-01

N.D. Admin. Code 43-02-10-06 Incremental production determination for a secondary recovery project. 1.a.In a unit where there has not been a secondary recovery project, the commission will establish a primary production decline curve. In such instance, incremental production is the production above the established primary production decline curve which production is a result of the secondary recovery project

b.The total amount of primary production from the unit will be determined by the commission through the use of a computer-generated production decline curve developed by software used by the commission at the time of certification. The decline curve will be a production versus time plot. The oil production and the time used to develop the curve will be that production occurring and period of time from the latest peak in production through the last month of oil production prior to the month in which secondary recovery project operations commence. However, the director shall have discretionary authority to select a different period of time to establish the decline curve if deemed necessary to obtain a more accurate estimate of the ultimate primary production.

c.The production decline curve established in subdivision b of this subsection is projected from the end of the last month in which production was used to develop the primary decline curve to a producing rate of one barrel of oil per well per day, but no projection shall be made greater than fifty years in duration. All production above the projected decline curve is incremental production and production below the decline curve is primary production. The total projected primary production, on a monthly basis in numerical form, is derived from the projected primary production decline curve. A copy of the projected monthly primary production, in numerical form, will be furnished to the unit operator and the tax commissioner.

d.For purposes of determining the primary production provided for in this subsection, where practices and procedures used by the commission cannot be used because production has been restricted due to the prolific nature of the reservoir (such as a Lodgepole reservoir), where unitization is accomplished early in the life of the reservoir, and sufficient primary production history does not exist for decline curve analysis, the commission will have the authority to determine an alternate method using fundamental reservoir engineering principles. One example the commission might use is a pressure decline versus cumulative production plot to estimate the ultimate primary production.

Based on available data and reservoir characteristics an initial rate and decline percent would be extrapolated to match the estimated ultimate recovery. In this case the operating company would be required to monitor the reservoir pressure and production and coordinate all activities and measurements with the commission.

2.In a unit which commences a new secondary recovery project where a secondary recovery project was in existence prior to July 1, 1991, and the commission cannot establish an accurate production decline curve, incremental production will be determined pursuant to paragraph 2 of subdivision c of subsection 5 of North Dakota Century Code section 57-51.1-03. 3.a.In a unit which commences a new secondary recovery project where a secondary recovery project was in existence before July 1, 1991, and where the commission can establish an accurate production decline curve, incremental production is the production above the established production decline curve which production is a result of the new secondary recovery project.

b.The total amount of oil that would have been produced from the unit if the new secondary software used by the commission at the time of certification. The decline curve will be a production versus time plot. The oil production and the time used to develop the curve will be that production occurring and period of time from the latest peak in production through the last month of oil production prior to the month in which the new secondary recovery project operations commence. However, the director shall have discretionary

authority to select a different period of time to establish the decline curve if deemed necessary to obtain a more accurate estimate of the ultimate production that would have been produced if the new secondary recovery project had not been commenced.

c.The production decline curve established in subdivision b of this subsection is projected from the end of the last month in which production was used to develop the decline curve to a producing rate of one barrel of oil per well per day. All production above the projected decline curve is incremental production and production below the decline curve is production which would have occurred in the absence of the new secondary recovery project. The total projected production below the curve, on a monthly basis in numerical form, is derived from the projected production decline curve. A copy of the projected monthly production below the curve, in numerical form, will be furnished to the unit operator and the tax commissioner.

4.The commission will hold a hearing to establish a decline curve and a projection of the curve from which incremental production can be determined. At the hearing the project operator of a secondary recovery project or a new secondary recovery project must introduce evidence regarding the work proposed or accomplished which will result in incremental production, and evidence showing that the project is a qualifying project. Application for the hearing may, at the discretion of the project operator, be made prior or subsequent to the commencement of a secondary recovery project or commencement of a new secondary recovery project.

History

• History: Effective May 1, 1992; amended effective February 1, 1998; July 1, 2002.
• Law Implemented: NDCC 38-08-04, 57-51.1-01

N.D. Admin. Code 43-02-10-07 Incremental production determination for a tertiary recovery project. 1.a.In a unit where there has not been a secondary recovery project and a tertiary project is commenced, the commission will establish a primary production decline curve. In such instance, incremental production is the production above the established primary production decline curve which production is a result of the tertiary recovery project

b.The total amount of oil that would have been produced from the unit if the tertiary software used by the commission at the time of certification. The decline curve will be a production versus time plot. The oil production and the time used to develop the curve will be that production occurring and period of time from the latest peak in production through the last month of oil production prior to the month in which the tertiary recovery project operations commence. However, the director shall have discretionary authority to select a different period of time to establish the decline curve if deemed necessary to obtain a more accurate estimate of the ultimate primary production.

c.The production decline curve established in subdivision b of this subsection is projected from the end of the last month in which production was used to develop the primary decline curve to a producing rate of one barrel of oil per well per day. All production above the projected decline curve is incremental production and production below the decline curve is primary production. The total projected primary production, on a monthly

basis in numerical form, is derived from the projected primary production decline curve. A copy of the projected monthly primary production, in numerical form, will be furnished to the unit operator and the tax commissioner.

2.In a unit which commences a tertiary recovery project where there is or has been a secondary recovery project and the commission cannot establish an accurate production decline curve, incremental production will be determined pursuant to paragraph 5 of subdivision c of subsection 5 of North Dakota Century Code section 57-51.1-03. 3.a.In a unit which commences a tertiary recovery project where there is or has been a secondary recovery project and where the commission can establish an accurate production decline curve, incremental production is the production above the established production decline curve which production is a result of the tertiary recovery project.

b.The total amount of oil that would have been produced from the unit if the tertiary software used by the commission at the time of certification. The decline curve will be a production versus time plot. The oil production and the time used to develop the curve will be that production occurring and period of time from the latest peak in production through the last month of oil production prior to the month in which the tertiary recovery project operations commence. However, the director shall have discretionary authority to select a different period of time to establish the decline curve if deemed necessary to obtain a more accurate estimate of the ultimate production that would have been produced if the tertiary recovery project had not been commenced.

c.The production decline curve established in subdivision b of this subsection is projected from the end of the last month in which production was used to develop the decline curve to a producing rate of one barrel of oil per well per day. All production above the projected decline curve is incremental production and production below the decline curve is production which would have occurred in the absence of the tertiary recovery project.

The total projected production below the curve, on a monthly basis in numerical form, is derived from the projected production decline curve. A copy of the projected monthly production below the curve, in numerical form, will be furnished to the unit operator and the tax commissioner.

4.The commission will hold a hearing to establish a decline curve and a projection of the curve from which incremental production can be determined. At the hearing the project operator of a tertiary recovery project must introduce evidence regarding the work proposed or accomplished which will result in incremental production, and evidence showing that the project is a qualifying project. Application for the hearing may, at the discretion of the project operator, be made prior or subsequent to the commencement of a tertiary recovery project.

History

• History: Effective May 1, 1992.

N.D. Admin. Code 43-02-10-08 Books and records to be kept to substantiate reports

Any unit operator desiring to certify a secondary recovery project shall make and keep appropriate books and records for a period of not less than six years, covering their operations in North Dakota from which they may be able to make and substantiate the reports required by this chapter.

History

• History: Effective September 1, 2000.
• Law Implemented: NDCC 38-08-04

Chapter 43-02-11 Certification of Shallow Gas Wells

N.D. Admin. Code 43-02-11-01 Definitions

The terms used throughout this chapter have the same meaning as in chapter 43-02-03 and North Dakota Century Code chapter 38-08 except shallow gas and shallow gas zone are defined under North Dakota Century Code chapter 57-51.

History

• History: Effective July 1, 1996; amended effective July 1, 2002; May 1, 2004; April 1, 2018.
• Law Implemented: NDCC 38-08-04, 57-51-01, 57-51.1-03

N.D. Admin. Code 43-02-11-02 Application to certify as qualifying a horizontal well, horizontal reentry well, or two-year inactive well for taxable events occurring through December 31, 2015. 43-02-11-02.1. Application to certify as a shallow gas well

Any operator desiring to certify a shallow gas well for purposes of eligibility for the tax incentive provided in North Dakota Century Code chapter 57-51 shall submit to the director an application for certification of the well. The operator has the burden of establishing entitlement to certification and shall submit all data necessary to enable the commission to determine whether the well qualifies and is entitled to the tax exemption provided in North Dakota Century Code section 57-51-02.4.

History

• History: Effective May 1, 2004.
• Law Implemented: NDCC 38-08-04, 57-51-01

N.D. Admin. Code 43-02-11-03 Application for a tax exemption and reduction for a new well

Repealed effective July 1, 2002.

N.D. Admin. Code 43-02-11-04 Application for tax exemption and reduction for a horizontal well

N.D. Admin. Code 43-02-11-05 Application for tax exemption and reduction for a horizontal reentry well

N.D. Admin. Code 43-02-11-06 Application for tax exemption and reduction for a two-year inactive well

N.D. Admin. Code 43-02-11-07 Books and records to be kept to substantiate reports

Any operator desiring to certify a shallow gas well shall make and keep appropriate books and records for a period of not less than six years, covering their operations in North Dakota from which they may be able to make and substantiate the reports required by this chapter.

History

• History: Effective September 1, 2000; amended effective April 1, 2018.
• Law Implemented: NDCC 38-08-04, 57-51

N.D. Admin. Code 43-02-11-08 Application for tax exemption for a shallow gas well

The application must include the following:

1.The name and address of the applicant and the name and address of the person operating the well if different.

2.The name and number of the well and the legal description of the surface location of the well for which a determination is requested.

3.The date the well was spudded and its completion date.

4.The name and the depth to the bottom of the productive strata or formation.

If the application does not contain sufficient information to make a determination, the director may require the applicant to submit additional information.

History

• History: Effective May 1, 2004; amended effective April 1, 2018.
• Law Implemented: NDCC 38-08-04, 57-51

Chapter 43-02-12 Geophysical Exploration Requirements

N.D. Admin. Code 43-02-12-01 Definitions

The terms used in this chapter have the same meaning as in North Dakota Century Code chapter 38-08.1 except:

1."Building" means any residence or commercial structure including a barn, stable, or other similar structure.

2."Director" means the director of oil and gas of the industrial commission, the assistant director of oil and gas of the industrial commission, and their designated representatives.

This chapter contains general rules of statewide application which have been adopted by the industrial commission to govern geophysical exploration in North Dakota. Special rules, regulations, and orders have been and will be issued when required and shall prevail as against general rules, regulations, and orders if in conflict therewith. However, wherever this chapter does not conflict with special rules heretofore or hereafter adopted, this chapter will apply in each case. The commission may grant exceptions to this chapter, after due notice and hearing, when such exceptions will protect correlative rights.

History

• History: Effective December 1, 1997; amended effective September 1, 2000; January 1, 2006.
• Law Implemented: NDCC 38-08.1-01 43-02-12-01.1. Scope of chapter.
• History: Effective April 1, 2010.

N.D. Admin. Code 43-02-12-02 Certification to do business within state - Resident agent

Any person desiring to engage in geophysical exploration within this state, including a contractor and subcontractor, shall obtain from the secretary of state a certificate of authority to transact business in this state. A copy of this certificate must be filed with the commission prior to, or together with, the bond required herein and the application for permit to engage in geophysical exploration.

History

• History: Effective December 1, 1997.
• Law Implemented: NDCC 38-08.1-03

N.D. Admin. Code 43-02-12-03 Bonding requirements

1.To satisfy the obligation that a geophysical exploration contractor desiring to engage in geophysical exploration shall file with the commission a good and sufficient surety bond, the contractor, in lieu of a surety bond, may post cash or a certificate of deposit with the Bank of North Dakota. Persons desiring to file a cash bond or certificate of deposit shall file with the commission an application to deposit cash or certificate of deposit. If the applicant is currently in compliance with the statutes, rules, and orders of the commission, the commission will issue to the Bank of North Dakota a compliance statement authorizing the Bank of North Dakota to accept cash or a certificate of deposit as a bond for the applicant.

2.Geophysical exploration contractors shall file with the commission a good and sufficient bond in the amount of fifty thousand dollars if the contractor intends to conduct shot hole operations or in the amount of twenty-five thousand dollars if the contractor intends to use any other method of geophysical exploration. Each subcontractor engaged by the geophysical exploration contractor for the drilling and plugging of seismic shot holes shall file with the commission a good and sufficient bond in the amount of ten thousand dollars.

History

• History: Effective December 1, 1997.
• Law Implemented: NDCC 38-08.1-03.1

N.D. Admin. Code 43-02-12-04 Exploration permit - Application - Expiration

1.Any person applying to the commission for an exploration permit must have a certificate to conduct geophysical exploration pursuant to subsection 3 of North Dakota Century Code

section 38-08.1-03.1. A person may not commence geophysical exploration activities in this state without first obtaining an exploration permit from the commission. An application for an exploration permit must be submitted to the commission at least three business days before commencing operations and include the following:

a.The name, permanent address, and telephone number of the geophysical contractor and the geophysical contractor's local representative.

b.The name, permanent address, and telephone number of the drilling and hole plugging contractor, if different from the seismic contractor.

c.The name and address of the resident agent for service of process of the person intending to engage in geophysical exploration.

d.The bond number, type, and amount for the geophysical company.

e.The geophysical exploration method (i.e., shot hole, nonexplosive, 2D, or 3D).

f.The number, depth, and location of the seismic holes and the size of the explosive charges, if applicable.

g.The anticipated starting date of seismic and plugging operations.

h.The anticipated completion date of seismic and plugging operations.

i.A description of hole plugging procedures.

j.A preplot map displaying the proposed seismic source points and receiver lines and specifically identifying all source points that do not comply with section 43-02-12-05.

k.A fee of one hundred dollars.

2.The permitholder shall notify the commission at least twenty-four hours, excluding Saturdays and holidays, before commencing geophysical activity.

3.The permitholder shall immediately notify the commission of any revisions to an approved seismic permit.

4.An exploration permit expires one year after the date it was issued, unless geophysical exploration activities have commenced.

History

• History: Effective December 1, 1997; amended effective September 1, 2000; May 1, 2004; April 1, 2010; April 1, 2014.
• Law Implemented: NDCC 38-08.1-04.1

N.D. Admin. Code 43-02-12-05 Distance restrictions - Shot hole operations - Nonexplosive methods

Seismic shot hole operations may not be conducted less than six hundred sixty feet [201.17 meters] from water wells, buildings, underground cisterns, pipelines, and flowing springs.

Nonexplosive exploration methods may not be conducted less than three hundred feet [91.44 meters] from water wells, buildings, underground cisterns, pipelines, and flowing springs.

Variances may be granted to this section by written agreement between the permitholder and the owner of the subject property and must be available to the director upon request.

History

• History: Effective December 1, 1997; amended effective September 1, 2000; May 1, 2004.

N.D. Admin. Code 43-02-12-06 Notification of work performed

The director may require progress reports prior to the completion of a project. Within thirty days following the completion of geophysical exploration by any person within this state, such person shall file with the commission a seismic completion report in the form of an affidavit deposing that the seismic project was completed in accordance with chapter 43-02-12, and incorporating a postplot map displaying the actual source point location and the location of all undetonated (loaded) holes, blowouts, and flowing holes or any other problem holes the director deems necessary. If obtained by the contractor, the latitude and longitude of each source and receiver point shall be submitted to the commission to the nearest tenth of a second.

Any person plugging a seismic hole must submit a plugging report and an affidavit of plugging detailing the line number, shot point number, hole depth, drill type, hole condition (wet, dry), bentonite used (sacks, capsules), and the depth at which the surface plug was set, and all other information necessary to describe the conditions of the shot hole.

The director is authorized to approve an operator's request to suspend a geophysical exploration project, although no suspension shall be granted beyond ninety days unless all charges are detonated.

The director is authorized to suspend operations of the entire geophysical exploration project, or any portion thereof, if further activity will cause excessive damage to the surface of the land. The geophysical exploration activity may continue upon the director approving a plan to mitigate the damage.

History

• History: Effective December 1, 1997; amended effective September 1, 2000; May 1, 2004; January 1, 2008; April 1, 2010; April 1, 2012.
• Law Implemented: NDCC 38-08.1-02, 38-08.1-05

N.D. Admin. Code 43-02-12-07 Drilling and plugging requirements

1.Prior to commencement of any drilling or plugging operations, the director may require a field meeting with the geophysical contractor and subcontractors.

2.Except in those circumstances in which the director allows otherwise, all seismic shot holes must be plugged the same day as they were drilled and loaded. Any blown out shot holes must be plugged as soon as reasonably practicable, unless, upon application, the director grants an extension which may not exceed ninety days. All seismic shot holes must be temporarily capped until final plugging.

3.If the number of drilling rigs on a proposed project exceeds the director's capacity to provide appropriate inspection, the director may limit the number of drilling rigs.

4.Bentonite materials used in seismic hole plugging must be derived from naturally occurring untreated, high swelling sodium bentonite which consists principally of the mineral montmorillonite.

5.A durable nonmetallic plug, designed to fit the hole, must be set at a depth of approximately three feet [91.44 centimeters] below the surface of every shot hole.

6.Unless the contractor can prove to the satisfaction of the commission that another method will provide better protection to ground water and long-term land stability, seismic shot hole plugging shall be conducted in the following manner:

a.When water is used in conjunction with the drilling of seismic shot holes or when water is encountered in the hole, the shot holes are to be filled with coarse ground bentonite approximately three-fourths of one inch [19.05 millimeters] in diameter from the top of the charge up to a depth above the final water level. Cuttings shall be added from the top of the bentonite to the surface. Only dry cuttings shall be utilized when plugging the shot hole. All cuttings added above the nonmetallic plug shall be tamped.

b.When drilling with air only, and in completely dry holes, a plugging may be accomplished by returning the cuttings to the hole. A small mound must be left over the hole for settling allowance.

c.Remaining cap leads must be cut off below ground level and any drilling fluid or cuttings which are deposited on the surface around the seismic hole will be spread out in such a manner that the growth of natural grasses or foliage will not be impaired.

d.Any markings, including lath, pin flags, flagging, or any other debris left on the project area, including the powder magazine, must be removed and lawfully disposed of.

History

• History: Effective December 1, 1997; amended effective September 1, 2000; May 1, 2004; April 1, 2014.
• Law Implemented: NDCC 38-08.1-02, 38-08.1-06, 38-08.1-06.1

N.D. Admin. Code 43-02-12-08 Books and records to be kept to substantiate reports

All geophysical, drilling, and plugging contractors shall make and keep appropriate books and records for a period of not less than six years, covering their operations in North Dakota from which they may be able to make and substantiate the reports required by this chapter.

History

• History: Effective September 1, 2000.

Chapter 43-02-13 High-Level Radioactive Waste

N.D. Admin. Code 43-02-13-01 Definitions

The terms used throughout this chapter have the same meaning as in North Dakota Century Code chapters 38-23 and 38-08 except:

1."Active institutional controls" are the means used to control access to an open or closed high-level radioactive waste disposal site by anything other than passive institutional controls.

Active institutional controls include fencing, guards, security cameras, etc.

2."Certified or registered mail" means any form of service by the United States postal service, federal express, Pitney Bowes, and any other commercial, nationwide delivery service that provides the mailer with a document showing the date of delivery or refusal to accept delivery.

3."High-level radioactive waste facility" as defined in North Dakota Century Code section 38-23-02 also includes all surface structures (buildings, slabs or pads, tunnels, pipelines, etc.) for either a storage or a disposal facility as well as all subsurface structures, disposal wells, and caverns.

4."Occupied dwelling" or "permanently occupied dwelling" means a residence that is lived in by a person at least six months throughout a calendar year.

5."Passive institutional controls" are permanent markers or structures intended to reduce the likelihood of humans unintentionally intruding into a high-level radioactive waste disposal site for thousands of years after it is closed.

6."Well" means any hole drilled for the purpose of information gathering, storage, or disposal of high-level radioactive waste.

N.D. Admin. Code 43-02-13-02 Scope of chapter

This chapter contains general rules of statewide application which have been adopted by the industrial commission to regulate the exploration, testing, placement, storage, and disposal of high-level radioactive waste to provide for operation in a manner as to protect the citizens of North Dakota. The commission may grant exceptions to this chapter, after due notice and hearing, when such exceptions will result in effectuating the purpose and intent of North Dakota Century Code chapter 38-23.

N.D. Admin. Code 43-02-13-03 Enforcement of laws, rules, and regulations dealing with exploration, development, and storage or disposal of high-level radioactive wastes

The commission, its agents, representatives, and employees are charged with the duty and obligation of enforcing all rules and statutes of North Dakota relating to high-level radioactive waste.

However, it shall be the responsibility of all owners, operators, and contractors of high-level radioactive waste facilities to obtain information pertaining to the regulation of high-level radioactive waste disposal before operations have begun.

N.D. Admin. Code 43-02-13-04 Waste prohibited

All operators, contractors, drillers, carriers, service companies, and all other persons at all times shall conduct their operations in the drilling, plugging, storage, disposal, and site reclamation of high-level radioactive waste in a manner that will prevent waste and prevent the release of radioactive materials into the environment.

N.D. Admin. Code 43-02-13-05 Forms upon request

Forms for written notices, requests, and reports required by the commission must be furnished upon request. These forms must be of such nature as prescribed by the commission to cover proposed work and to report the results of completed work.

N.D. Admin. Code 43-02-13-06 Authority to cooperate with other agencies

The commission from time to time may enter arrangements with state and federal government agencies, industry committees, and individuals with respect to special projects, services, and studies relating to high-level radioactive waste disposal.

N.D. Admin. Code 43-02-13-07 Organization reports

Every person acting as principal or agent for another or independently engaged in the exploration, drilling, testing, placement, storage, and disposal of high-level radioactive waste or retains ownership of equipment used for high-level radioactive waste storage or disposal or retains ownership of high-level radioactive waste facilities in North Dakota immediately shall file with the state geologist the name under which such business is being conducted and operated; the name and post office address of such person; the business or businesses in which the person is engaged; the plan of organization, and in case of a corporation, the law under which it is chartered; and the names and post office addresses of any person acting as trustee, together with the names and post-office addresses of any officials on an organization report. If such business is conducted under an assumed name, such organization report must show the names and post office addresses of all owners in addition to the other information required. A new organization report must be filed when there is a change in any of the information contained in the report.

N.D. Admin. Code 43-02-13-08 Geotechnical and geophysical surveys

By special order of the commission, periodic surveys may be made of both the rock containing high-level radioactive waste and the rocks above and below it. These surveys must be thorough and complete and must be made using methods approved by the director. The condition of the rocks containing high-level radioactive waste and the practices and methods employed by the operators must be investigated. All operators shall permit and assist the agents of the commission in making any and all special tests that may be required by the commission on any or all exploration wells, disposal wells, disposal caverns, or storage sites. All geophysical operations shall comply with North Dakota Century Code chapter 38-08.1.

N.D. Admin. Code 43-02-13-09 Access to property and records

The commission, director, and their representatives shall have access to all exploration test well, storage and disposal well, and high-level radioactive waste facility records wherever located. All owners, operators, drilling contractors, drillers, service companies, or other persons engaged in drilling, completing, or servicing wells or constructing, servicing, and maintaining facilities shall permit the commission, director, and their representatives to come upon any property, well, or drilling rig operated or controlled by them, complying with state safety rules and to inspect the records and operation of such wells, and to have access at all times to any and all records of wells. If requested, copies of such records must be filed with the commission.

N.D. Admin. Code 43-02-13-10 Test well bond

Before any person receives a permit to drill a test well or perform a test that causes surface disturbance while exploring for a high-level radioactive waste disposal site, the person shall submit to the commission and obtain its approval of a surety bond or cash bond. An alternate form of security may be approved by the commission after notice and hearing, as provided by law. The operator of a test well or other types of exploration or testing that causes surface disturbance shall be the principal on the bond covering such activity. Each such surety bond must be executed by a responsible surety company authorized to transact business in North Dakota. The bond must be based upon the estimated costs to plug the test well at the projected total depth and the surface restoration costs. Bonds must be conditioned upon full compliance with North Dakota Century Code chapter 38-23, and all administrative rules and orders of the commission, and continues until the test well has been satisfactorily plugged which must include practical reclamation of the well site and appurtenances, and all logs, plugging records, and other pertinent data required by statute or rules and orders of the commission are filed and approved.

Bond termination. The commission, in writing, shall advise the principal and any sureties on any bond as to whether the plugging and reclamation is approved. If approved, liability under such bond may be terminated formally upon receipt of a written request by the principal. The request must be signed by an officer of the principal or a person authorized to sign for the principal.

Director's authority. The director is vested with the power to act for the commission as to all matters within this section, except requests for alternative forms of security, which only may be approved by the commission. The commission may refuse to accept a bond if the operator or surety company has failed in the past to comply with statutes, rules, or orders relating to the operation of wells or high-level radioactive waste facilities; if a civil or administrative action brought by the commission is pending against the operator or surety company; or for other good cause.

N.D. Admin. Code 43-02-13-11 Facility bond

Before any person receives a permit to construct a high-level radioactive waste facility, the person shall submit to the commission and obtain its approval of a surety bond or cash bond. An alternate form of security may be approved by the commission after notice and hearing, as provided by law. The operator of a high-level radioactive waste facility shall be the principal on the bond covering such activity. Each such surety bond must be executed by a responsible surety company authorized to transact business in North Dakota. The amount of the bond must be based upon the size and scope of the facility and all costs associated with its reclamation. Bonds must be conditioned upon full compliance with North Dakota Century Code chapter 38-23, and all administrative rules and orders of the commission, and continues until the high-level radioactive waste facility, including surface facilities and all disposal wells or subsurface caverns have been satisfactorily plugged and reclaimed pursuant to chapter 43-02-03 and all logs, plugging records, and other pertinent data required by statute or rules and orders of the commission are filed and approved.

Bond termination. The commission, in writing, shall advise the principal and any sureties on any bond as to whether the plugging and reclamation is approved. If approved, liability under such bond may be terminated formally upon receipt of a written request by the principal. The request must be signed by an officer of the principal or a person authorized to sign for the principal.

Director's authority. The director is vested with the power to act for the commission as to all matters within this section, except requests for alternative forms of security, which only may be approved by the commission. The commission may refuse to accept a bond if the operator or surety company has failed in the past to comply with statutes, rules, or orders relating to the operation of high-level radioactive waste facilities; if a civil or administrative action brought by the commission is pending against the operator or surety company; or for other good cause.

The size and the scope of the operation must be evaluated annually and the department may increase or decrease the bond amount to reflect the results of the evaluation.

N.D. Admin. Code 43-02-13-12 Exploration permit

A permit is required prior to commencement of operations for the drilling, boring, excavating, testing, and either land-based or airborne geophysical surveying for the purpose of exploring for a high-level radioactive waste facility. It is unlawful to proceed with these activities without first obtaining an exploration permit from the commission.

The application for a permit to drill must be filed with the director, together with a permit fee to be determined by the state geologist based upon the cost for the commission to review, investigate, and process the application. The permit application must be accompanied by a notice of opportunity for a position paper, from the commissioners of the county where the proposed exploration drilling will take place. No activity may commence until such application is approved and a permit to explore is issued by the commission. The application must be accompanied by the bond pursuant to section 43-02-13-11 or the applicant previously must have filed such bond with the commission, otherwise the application is incomplete. An incomplete application received by the commission has no standing and will not be deemed filed until it is complete.

A permit is required for each test well or each method of exploration. The area to be explored must be outlined on the application and the permit shall be valid in the area so outlined. The application for permit to drill must be accompanied by an accurate plat certified by a registered surveyor showing the location of the proposed well with reference to true north and the nearest lines of a governmental

section. The plat also must include latitude and longitude of the proposed test well location to the nearest tenth of a second. Information to be included in such application must be the proposed depth to which the test well will be drilled; estimated depth to the top of important stratigraphic markers; estimated depth to the top of objective horizons; the proposed mud program; the proposed casing program, including size and weight; the depth at which each casing string is to be set; the proposed pad layout, including cut and fill diagrams; and the proposed amount of cement to be used, including the estimated top of the cement, the proposed procedure, and the estimated completed total depth.

The drilling, testing, and plugging of exploratory test wells must comply with all applicable rules in

section 43-02-03.

The exploration permit is in effect for one year.

N.D. Admin. Code 43-02-13-13 Facility permit

A facility permit application is required prior to commencement of operations to create or construct a high-level radioactive waste facility. The application for a high-level radioactive waste facility permit must be filed with the director, together with a permit fee. The amount of the permit fee is determined by the state geologist based upon the cost for the commission to review, investigate, and process the application. The permit application must be accompanied by a notice of opportunity for a position paper, from the commissioners of the county where the proposed facility will be located. No activity may commence until such application is approved and a permit to explore is issued by the director. The application must be accompanied by the bond pursuant to section 43-02-13-12 or the applicant previously must have filed such bond with the commission, otherwise the application is incomplete. An incomplete application received by the commission has no standing and may not be deemed filed until it is complete.

Prior to the issuance of a permit, the operator shall deposit one hundred million dollars or one million dollars per permitted acre, whichever is the greater amount, into the high-level radioactive waste fund. The deposit amount is to be adjusted to reflect any increase in the consumer price index published by the United States department of labor from the year 2020 to the consumer price index published by the department of labor at the time of the construction of the project. The half-lives of some of the radioactive waste will be dangerous much longer than any sign, monument, or avoidance structures would remain unless they are maintained in perpetuity. This money is to be used to ensure the passive institutional controls are maintained for thousands of years.

The high-level radioactive waste facility permit application must include:

1.A description of the high-level radioactive waste facility to be permitted. The area of the facility must be outlined on the application and the permit shall be valid in the area so outlined. The facility application must be accompanied by an accurate plat certified by a registered surveyor showing the location of the proposed facility and well with reference to true north and the nearest lines of a governmental section. The plat also must include latitude and longitude of the proposed storage or disposal location to the nearest tenth of a second.

2.High-level radioactive waste facility information will include the proposed depth to which the storage or disposal hole will be drilled; estimated depth to the top of important stratigraphic markers; estimated depth to the top of objective horizons; the proposed mud program; the proposed casing program, including size and weight; the depth at which each casing string is to be set; the proposed pad layout, including cut and fill diagrams; and the proposed amount of cement to be used, including the estimated top of the cement, the proposed procedure, and the estimated completed total depth. The drilling, testing, disposal, and plugging of high-level radioactive waste facility disposal wells must comply with all applicable rules in chapter 43-02-03.

3.A detailed description of the high-level radioactive material to be stored or disposed.

4.A detailed description of the mechanical construction and operating procedures of the high-level radioactive waste facility.

5.A justification for the need for the high-level radioactive waste facility to be permitted, including economic impact.

6.A detailed discussion and description of the subsurface geology and hydrology of the area to be affected by the construction and operation of the high-level radioactive waste facility.

7.A detailed discussion and description of the monitoring system to be used to ascertain the integrity of the high-level radioactive waste facility and to ensure compliance with this chapter.

8.A detailed description and discussion of a reclamation program for the restoration of the surface as nearly as possible to its original condition and productivity upon expiration of the permit or termination of any activities regulated by North Dakota Century Code chapter 38-23 and this chapter.

9.A detailed discussion and description of the active institutional controls that would be used while the facility is in operation.

10.A detailed discussion and description of the active institutional controls that would be used for a specified period of time after the facility has closed.

11.A detailed discussion and description of the passive institutional controls that would be constructed after the facility has closed, including estimated costs and the projected durability of the controls over thousands of years.

12.Architectural plans for all buildings and infrastructure within the facility boundaries.

13.Any other information required by the commission.

The length and terms of the permit must be decided by the commission but may not exceed five years. An application for a permit renewal must be made at least one hundred twenty days before the expiration of the valid permit and is subject to all of the procedures and requirements of this chapter.

N.D. Admin. Code 43-02-13-14 County zoning authority in the permitting process

Prior to a person submitting either an exploration permit or a facility permit, the person shall confirm the size, scope, and location of the project conforms to the county zoning regulations.

History

• General Authority: NDCC 38-23-09
• Law Implemented: NDCC 38-23-09

N.D. Admin. Code 43-02-13-15 Notice and hearing

A permit may be issued only after notice and hearing and the notice must follow Rule 4 of the North Dakota Rules of Civil Procedure. The permit applicant must follow the notification and publication requirements in North Dakota Century Code section 38-23-04.

N.D. Admin. Code 43-02-13-16 Permit review timelines

The commission may take up to six months to review and approve or deny an exploration permit.

During that time, the commission shall review the exploration permit, bring the exploration permit application before the advisory council, and hold a hearing on the exploration permit application.

The commission may take up to twelve months to review and approve or deny a high-level radioactive waste facility permit. During that time, the commission shall review the high-level radioactive waste facility permit, bring the high-level radioactive waste facility permit application before the advisory council, and hold a hearing on the high-level radioactive waste facility permit application.

N.D. Admin. Code 43-02-13-17 Notice of disapproval

The notice of disapproval to be issued to Congress within the time period mandated by the federal Nuclear Waste Policy Act. The notice of disapproval to be accompanied by a statement of reasons explaining why the commission disapproved of the recommended repository site.

N.D. Admin. Code 43-02-13-18 Federal agencies and federal regulations

Any high-level radioactive waste facility shall comply with all applicable federal regulations including those of the nuclear regulatory commission, Title 10, Code of Federal Regulations, and the environmental protection agency, 40 Code of Federal Regulations, Part 191.

N.D. Admin. Code 43-02-13-19 Site construction

In the construction of a well site, access road, and all associated facilities, the topsoil must be removed, stockpiled, and stabilized or otherwise reserved for use when the area is reclaimed. "Topsoil" means the suitable plant growth material on the surface; however, in no event may this be deemed to be more than the top twelve inches [30.48 centimeters] of soil or deeper than the depth of cultivation, whichever is greater. Soil stabilization materials, liners, fabrics, and other materials to be used onsite, on access roads or associated facilities, must be reported on a sundry notice to the director within thirty days after application. The reclamation plan for such materials also must be included. When necessary to prevent pollution of the land surface and freshwaters, the director may require the site to be sloped and diked. Sites may not be located in, or hazardously near, bodies of water, nor may the sites block natural drainages. Sites and associated facilities must be designed to divert surface drainage from entering the site. Sites or appropriate parts thereof must be fenced if required by the director. Sites must be stabilized to prevent erosion.

N.D. Admin. Code 43-02-13-20 Geologic data

The following basic data collected by the operator must be delivered, free of charge, to the state geologist within thirty days of collection:

1.Washed and packaged sample cuts.

2.Cores, except those portions used for necessary testing or analysis, in which case the results of testing, the analysis, and the description of missing portions must be submitted to the state geologist.

3.Copies of all logs, including sample logs, radioactivity logs, resistivity logs, and other types of electrical or mechanical logs.

4.Elevation and location information on the data collection points.

5.Other pertinent information required by the state geologist.

N.D. Admin. Code 43-02-13-21 Reports

Monthly reports on well activities, including drilling, completion, waste insertion, and plugging must be submitted to the state geologist. The amount of high-level radioactive waste in temporary storage, long-term storage, or has been disposed also must be reported on a monthly basis, due on the fifth day of the following month. Forms for written notices, requests, and reports required by the commission must be furnished upon request. These forms must be of such nature as prescribed by the commission to cover proposed work and to report the results of completed work.

N.D. Admin. Code 43-02-13-22 Facility annual operating fee

The amount of the annual operating fee, pursuant to North Dakota Century Code section 38-23-03, is due on January fifteenth. The one million dollar minimum fee threshold to be adjusted to reflect any increase in the consumer price index published by the United States department of labor from the year 2020 to the consumer price index published by the United States department of labor at the time the fee is imposed.

N.D. Admin. Code 43-02-13-23 Reclamation of exploration test wells

The plugging and reclamation of exploration test wells must comply with all applicable rules in

chapter 43-02-03, including plugging and site reclamation. The commission may require the well bore to be filled with concrete or another approved plugging material from the base of the hole to the ground surface.

All lands disturbed during exploration must be reclaimed to a condition consistent with prior land use and productive capacity.

N.D. Admin. Code 43-02-13-24 Reclamation of facilities

The plugging and reclamation of high-level radioactive waste facilities must comply with all applicable rules in chapter 43-02-03. Well bore must be filled with concrete or another plugging material approved by the commission from the top of the waste to the ground surface.

All buildings and infrastructure not used for either site monitoring or security must be removed. All disturbed lands must be reclaimed to a condition consistent with prior land use and productive capacity.

The exceptions to this is the area that contains signs or structures that are to be placed over the site to warn or dissuade future generations from occupying the surface, drilling into the subsurface, or disturbing the disposal wells, shafts, or chambers given the long-term nature of the high-level radioactive waste.

Upon final closure of the waste disposal site, both active and passive institutional controls must be implemented in and around the site. The means and the length of time that active institutional controls are maintained must be determined by the commission after consulting with the advisory council. The signs and structures comprising the passive institutional controls must be determined by the commission after consulting with the advisory council. Documents containing the location and depth of the waste, well construction, plugging and reclamation information, years of operation, half-lives of the radioactive waste, and other pertinent data must be permanently stored in the local, state, and national archives.

N.D. Admin. Code 43-02-13-25 Hearings - Complaint proceedings - Emergency proceedings - Other proceedings

1.Except as more specifically provided in North Dakota Century Code section 38-08-11, the rules of procedure established in subsection 1 of North Dakota Century Code section 28-32-21 apply to proceedings involving a complaint and a specific-named respondent.

2.For proceedings that do not involve a complaint and a specific-named respondent the commission shall give at least fifteen days' notice, except in emergency, of the time and place of hearing thereon by one publication of such notice in a newspaper of general circulation in Bismarck, North Dakota, and in a newspaper of general circulation in the county where the land affected or some part thereof is situated, unless in some particular proceeding a longer period of time or a different method of publication is required by law, in which event such period of time and method of publication prevails. The notice must issue in the name of the commission and must conform to the other requirements provided by law.

N.D. Admin. Code 43-02-13-26 Investigatory hearings

The commission may hold investigatory hearings upon the institution of a proceeding or by motion of the commission. Notice of the hearing must be served upon all parties personally or by certified mail at least five days before the hearing.

N.D. Admin. Code 43-02-13-27 Official record

The evidence in each case heard by the commission, unless specifically excluded by the hearing officer, includes the certified directional surveys, and all oil, water, and gas production records, and all injection records on file with the commission.

Any interested party may submit written comments on or objections to the application prior to the hearing date. Such submissions must be received no later than five p.m. on the last business day prior to the hearing date and may be part of the record in the case if allowed by the hearing examiner.

Settlement negotiations between parties to a contested case are admissible only as governed by North Dakota Century Code section 28-32-24, although the hearing officer may strike such testimony from the record for good cause.

N.D. Admin. Code 43-02-13-28 Petitions for review of recommended order and oral arguments prohibited

Neither petitions for review of a recommended order nor oral arguments following issuance of a recommended order and pending issuance of a final order are allowed.

N.D. Admin. Code 43-02-13-29 Notice of order by mail

The commission may give notice of an order by mailing the order, and findings and conclusions upon which it is based, to all parties by regular mail provided it files an affidavit of service by mail indicating upon whom the order was served.

N.D. Admin. Code 43-02-13-30 Service and filing

All pleadings, notices, written motions, requests, petitions, briefs, and correspondence to the commission or commission employee from a party, or vice versa, relating to a proceeding after its commencement, must be filed with the director and entered in the commission's official record of the procedure provided the record is open at the time of receipt. All parties are entitled to receive copies upon request of any or all of the evidence in the record of the proceedings. The commission may charge for the actual cost of providing copies of evidence in the record. Unless otherwise provided by law, filing is complete when the material is entered in the record of the proceeding.

N.D. Admin. Code 43-02-13-31 Designation of examiners

The commission by motion may designate and appoint qualified individuals to serve as examiners.

The commission may refer any matter or proceeding to any legally designated and appointed examiner or examiners.

N.D. Admin. Code 43-02-13-32 Powers and duties of examiner

The commission by motion may limit the powers and duties of any examiner in any particular case to such issues or to the performance of such acts as the commission deems expedient; however, subject only to such limitation as may be ordered by the commission, the examiner or examiners to whom any matter or proceeding is referred under this chapter have full authority to hold hearings on such matter or proceeding in accordance with and pursuant to this chapter. The examiner may regulate all proceedings before the examiner and to perform all acts and take all measures necessary or proper for the efficient and orderly conduct of such hearing, including ruling on prehearing motions, the swearing of witnesses, receiving of testimony and exhibits offered in evidence, subject to such objections as may be imposed, and shall cause a complete record of the proceeding to be made and retained.

N.D. Admin. Code 43-02-13-33 Report of examiner

Upon the conclusion of any hearing before an examiner, the examiner promptly shall consider the proceedings in such hearing, and based upon the record of such hearing, the examiner shall prepare a report and recommendations for the disposition of the matter or proceeding by the commission. Such report and recommendations either must be accompanied by a proposed order or must be in the form of a proposed order and must be submitted to the commission.

N.D. Admin. Code 43-02-13-34 Commission order from examiner hearing

After receipt of the report and recommendations of the examiner, the commission shall enter its order disposing of the matter or proceeding.

N.D. Admin. Code 43-02-13-35 Prehearing motion practice

In a matter pending before the commission, all prehearing motions must be served by the moving party upon all parties affected by the motion. Service must be upon a party unless a party is represented by an attorney, in which case service must be upon the attorney. Service must be made by delivering a copy of the motion and all supporting papers in conformance with one of the means of service provided for in Rule 5(b) of the North Dakota Rules of Civil Procedure. Proof of service must be made as provided in Rule 4 of the North Dakota Rules of Civil Procedure or by the certificate of an attorney showing that service has been made. Proof of service must accompany the filing of a motion.

Any motion filed without proof of service is not properly before the commission.

Chapter 43-02-14 Geological Storage of Oil or Gas

N.D. Admin. Code 43-02-14-01 Definitions

The terms used throughout this chapter have the same meaning as in chapters 43-02-02.1, 43-02-03, and 43-02-05, and North Dakota Century Code chapters 38-08, 38-12, 38-25, and 47-31 except:

1."Facility area" means the areal extent of the storage reservoir or salt cavern.

2."Storage reservoir" means the total pore space occupied by the injected produced oil or gas during all phases of the project plus any reasonable or necessary horizontal buffer zones.

N.D. Admin. Code 43-02-14-02 Scope of chapter

This chapter pertains to the geological storage of hydrogen and produced oil or gas with little to no processing involved. If the rules differ from federal requirements on federally regulated storage facilities, the federal rules take precedence. The storage facility operator shall provide sufficient documentation to the director confirming the storage facility is federally operated. Applications filed with the commission proposing to inject gas for the purposes of enhanced oil or gas recovery will be processed under chapter 43-02-05. This chapter does not apply to class III injection wells used to create a salt cavern. Applications for class III wells are under the jurisdiction of the state geologist pursuant to chapter 43-02-02.1. The commission may grant exceptions to this chapter, after due notice and hearing, when such exceptions will result in the prevention of waste and operate in a manner to protect correlative rights. 43-02-14-02.1. Application of rules for geological storage.

All geological storage facilities, injection wells, and monitoring wells are also subject to the provisions of chapters 43-02-03, 43-02-05, and 43-05-01 where applicable. 43-02-14-02.2. Injection into underground source of drinking water prohibited.

Underground injection of oil or gas that causes or allows movement of fluid into an underground source of drinking water is prohibited. 43-02-14-02.3. Transitioning from enhanced oil or gas recovery to geological storage.

A storage facility operator injecting oil or gas for the primary purpose of geological storage into an oil and gas reservoir shall apply for a geological storage facility and injection well permit. In determining if there is an increased risk to underground sources of drinking water, the commission shall consider the following factors:

1.Increase in reservoir pressure within the injection zone.

2.Oil or gas injection rates.

3.Decrease in reservoir production rates.

4.Distance between the injection zone and underground sources of drinking water.

5.Suitability of the enhanced oil or gas recovery area of review delineation.

6.Quality of abandoned well plugs within the area of review.

7.The storage facility operator's plan for recovery of oil or gas at the cessation of injection.

8.The source and properties of the injected oil or gas.

9.Any additional site specific factors as determined by the commission. 43-02-14-02.4. Prohibition of unauthorized injection.

Any underground injection of oil or gas for the purpose of geological storage, except into a well authorized by permit issued under this chapter, is prohibited. The construction of any well or site or access road is prohibited until the permit authorizing construction of the well or site or access road has been issued. 43-02-14-02.5. Existing well conversion.

Storage facility operators seeking to convert an existing well to an injection well for the purpose of geological storage of oil or gas must demonstrate to the commission that the well is constructed in a manner that will ensure the protection of underground sources of drinking water.

N.D. Admin. Code 43-02-14-03 Books and records to be kept to substantiate reports

All owners, operators, drilling contractors, drillers, service companies, or other persons engaged in drilling, completing, operating, or servicing storage facilities shall make and keep appropriate books and records until dissolution of the storage facility, covering their operations in North Dakota from which they may be able to make and substantiate the reports required by this chapter.

N.D. Admin. Code 43-02-14-04 Access to records

The commission and the commission's authorized agents shall have access to all storage facility records wherever located. All owners, operators, drilling contractors, drillers, service companies, or other persons engaged in drilling, completing, operating, or servicing storage facilities shall permit the commission, or its authorized agents, to come upon any lease, property, well, or drilling rig operated or controlled by them, complying with state safety rules and to inspect the records and operation of wells and to conduct sampling and testing. Any information so obtained is public information. If requested, copies of storage facility records must be filed with the commission.

N.D. Admin. Code 43-02-14-05 Geological storage facility permit hearing

1.At least thirty days before the scheduled hearing, the applicant shall give notice of the hearing to persons outlined in North Dakota Century Code 38-25-04.

2.Notice given by the applicant must contain the following:

a.A legal description of the land within the oil or gas facility area.

b.The date, time, and place the commission will hold a hearing on the permit application.

c.A statement of purpose of the application.

d.A statement that a digital copy (.pdf format) of the permit may be obtained from the commission.

e.A statement that all comments regarding the geological storage facility permit application must be in writing and submitted to the commission by five p.m. on the last business day before the hearing date or presented at the hearing.

f.Storage in an oil and gas reservoir must contain:

(1)A statement that amalgamation of the pore space within the geological storage reservoir is required to operate the geological storage facility, which requires consent of persons who own at least fifty-five percent, unless otherwise provided for as outlined in North Dakota Century Code section 38-25-05, of the pore space, and a statement that the commission may require the pore space owned by (2)A statement that unitization of oil and gas minerals and oil and gas leases within the geological storage reservoir is required to operate the geological storage facility, which requires consent of persons who own at least fifty-five percent, unless otherwise provided for as outlined in North Dakota Century Code section 38-25-05, of the oil and gas minerals and oil and gas leases, and a statement that the commission may require the oil and gas minerals and oil and gas leases owned by

g.Storage in a saline reservoir must contain a statement that amalgamation of the pore space within the geological storage reservoir is required to operate the geological storage facility, which requires consent of persons who own at least sixty percent of the pore space, and a statement that the commission may require the pore space owned by

h.Storage in a salt cavern must contain:

(1)A statement that amalgamation of the pore space within the salt cavern is required to operate the geological storage facility, which requires consent of persons who own at least sixty percent of the pore space, and a statement that the commission may require the pore space owned by nonconsenting owners to be included in the geological storage facility.

(2)A statement that unitization of salt minerals and salt leases within the salt cavern is required to operate the geological storage facility, which requires consent of persons who own at least fifty-five percent of the salt minerals and salt leases, and a statement that the commission may require the salt minerals and salt leases owned by nonconsenting owners to be included in the geological storage facility. 43-02-14-05.1. Area of review and corrective action.

1.The storage facility operator shall prepare, maintain, and comply with a plan to delineate the area of review for a proposed storage facility, periodically re-evaluate the delineation, and perform corrective action that meets the requirements of this section and is acceptable to the commission. The requirement to maintain and implement a commission-approved plan is directly enforceable regardless of whether the requirement is a condition of the permit. As a

part of the storage facility permit application, the storage facility operator shall submit an area of review and corrective action plan that includes the following:

a.The method for delineating the area of review, results of the reservoir or geomechanical modeling and simulation, inputs that will be made, and the site characterization data on which the model will be based.

b.A description of:

(1)The re-evaluation date, not to exceed five years, at which time the storage facility operator shall re-evaluate the area of review.

(2)The monitoring and operational conditions that would warrant a re-evaluation of the area of review before the next scheduled re-evaluation date.

(3)How monitoring and operational data will be used to inform an area of review re-evaluation.

(4)How corrective action will be conducted to meet requirements of this section, and how corrective action will be adjusted if there are changes in the area of review.

2.The storage facility operator shall perform the following actions to delineate the area of review and identify all wells that require corrective action:

a.Applicable to oil and gas and saline reservoirs. Predict, using existing site characterization, monitoring and operational data, and reservoir modeling and simulation, the projected lateral and vertical migration of the injectate in the subsurface from the commencement of injection activities until the oil or gas movement ceases, or until the end of a fixed time as determined by the director:

(1)Be based on detailed geologic data collected to characterize the injection zone, confining zones, and any additional zones; and anticipated operating data, including injection pressures, rates, and total volumes over the proposed life of the storage project.

(2)Consider any geologic heterogeneities, other discontinuities, data quality, and their possible impact on model predictions.

(3)Consider potential migration through faults, fractures, and artificial penetrations.

b.Applicable to salt caverns. Using site-specific geology, cavern construction data acquired during dissolution mining, and geomechanical modeling, determine necessary buffers as setbacks for the following:

(1)Future drilling in the proximity of the cavern.

(2)Additional caverns.

3.The storage facility operator shall perform corrective action on all wells in the area of review that are determined to need corrective action, using methods designed to prevent the movement of injectate or fluid into or between underground sources of drinking water or other unauthorized zones.

4.At the re-evaluation date, not to exceed five years, as specified in the area of review and corrective action plan, or when monitoring and operational conditions warrant, the storage facility operator shall:

a.Re-evaluate the area of review in the same manner specified in subdivision a or b of subsection 2, whichever is applicable.

b.Identify all wells or caverns in the re-evaluated area of review in the same manner specified in subsection 2.

c.Perform corrective action on wells requiring action in the re-evaluated area of review in the same manner specified in subsection 3.

d.Submit an amended area of review and corrective action plan or demonstrate to the commission through monitoring data and modeling results that no amendment to the plan is needed. Any amendments to the plan are subject to the director's approval and must be incorporated into the permit.

5.All modeling inputs and data used to support area of review delineations and re-evaluations must be retained until project completion. Upon project completion, the storage facility operator shall deliver the records to the commission.

N.D. Admin. Code 43-02-14-06 Permit requirements - Storage in oil and gas reservoir

An application for a geological storage facility permit must include at least the following:

2.Address surface, pore space, and mineral ownership by filing the following:

a.An affidavit of mailing, including the name and address of each owner, certifying that all surface owners of record within the storage reservoir and one-half mile [.80 kilometer] adjacent have been notified of the proposed geological storage project.

b.An affidavit of mailing, including the name and address of each owner, certifying that all mineral lessees, mineral owners of record, pore space owners and pore space lessees of record within the storage reservoir and one-half mile [.80 kilometer] adjacent have been notified of the proposed geological storage project.

c.Legal descriptions of surface ownership of record within the storage reservoir and one-half mile [.80 kilometer] adjacent.

d.Legal descriptions of mineral lessees and mineral owners of record within the storage reservoir and one-half mile [.80 kilometer] adjacent.

e.Legal descriptions of pore space owners and pore space lessees of record within the storage reservoir and one-half mile [.80 kilometer] adjacent.

3.Applicant shall request a permit for all oil or gas injection wells, monitoring wells, and surface facilities by filing the following:

a.Application for permit to drill filed on a form provided by the director pursuant to chapter 43-02-03; and

b.Application for permit to inject filed on a form provided by the director including at least the following:

(1)The name and address of the operator of the injection well.

(2)The estimated bottom hole fracture pressure of the upper confining zone.

(3)Average maximum daily rate of oil or gas to be injected.

(4)Average and maximum requested surface injection pressure.

(5)Geologic name and depth to base of the lowermost underground source of drinking water which may be affected by the injection.

(6)Existing or proposed casing, tubing, and packer data.

(7)Existing or proposed cement specifications, including amounts and actual or proposed top of cement.

(8)A plat and maps depicting the area of review, based on the associated geological storage facility permit, and detailing the location, well name, and operator of all wells in the area of review. The plat and maps must include all injection wells, producing wells, plugged wells, abandoned wells, drilling wells, dry holes, permitted wells, water wells, surface bodies of water, and other pertinent surface features, such as occupied dwellings and roads.

(9)A review of the surficial aquifers within one mile [1.61 kilometers] of the proposed injection well site or surface facilities.

(10)Proposed injection program, including method of transportation of the oil or gas to the injection facility and the injection well.

(11)List identifying all source wells or sources of injectate.

(12)All logging and testing data on the well which has not been previously submitted.

(13)Schematic or other appropriate drawings and tabulations of the wellhead and surface facilities, including the size, location, construction, and purpose of all tanks, the height and location of all dikes and containment, including a calculated containment volume, all areas underlain by a synthetic liner, the location of all flow lines, and a tabulation of any pressurized flow line specifications. It must also include the proposed road access to the nearest existing public road and the

authority to build such access.

(14)A schematic drawing of the well detailing the proposed well bore construction, including the size of the borehole; the total depth and plug back depth; the casings and tubing sizes, weights, grades, and top and bottom depths; the perforated interval top and bottom depths; the packer depth; the injection zone; and upper and lower confining zones top and bottom depths.

(15)A detailed description of the proposed completion or conversion procedure, including any proposed well stimulation.

(16)Any other information required by the director to evaluate the proposed well.

4.A map showing the extent of the pore space that will be occupied by the injection and

5.A map showing the outside boundary of the oil or gas facility area, its delineated area of review, and the surface and bottom hole location of all proposed injection wells, monitoring

6.Structural and stratigraphic cross sections that describe the geological conditions of the geological storage reservoir.

7.A structure map of the top and base of the geological storage reservoir.

8.An isopach map of the geological storage reservoir.

9.Identification of all structural spill points or stratigraphic discontinuities controlling the isolation of stored oil or gas and associated fluids within the geological storage reservoir.

10.Geomechanical information sufficient to demonstrate that the confining zone is free of transmissive faults or fractures and of sufficient areal extent and integrity to contain the injected oil or gas stream.

11.Any known regional or local faulting. If faults are known or suspected, a cross section that

12.A method for delineating the area of review, including the computational model to be used, assumptions that will be made, and the site characterization data on which the model will be

13.A map of all wells, including all injection wells, producing wells, plugged wells, abandoned wells, drilling wells, dry holes, water wells, and other subsurface structures within the oil or gas

14.A determination that all abandoned wells have been properly plugged and all operating wells have been constructed in a manner that prevents the oil or gas or associated fluids from escaping the geological storage reservoir.

15.A tabular description and well bore diagram of each well's type, construction, date drilled,

16.Quantitative analysis from a state-certified laboratory of freshwater from all available freshwater wells within the oil or gas facility area and its delineated area of review. The location of all wells by quarter-quarter, section, township, and range must also be submitted.

This requirement may be waived by the director in certain instances.

17.Quantitative analysis from a third-party laboratory of a representative sample of the oil or gas to be injected. A compatibility analysis with the receiving formation may also be required.

18.A map showing all occupied dwellings within the oil or gas facility area and its delineated area of review.

19.Corrective action plan pursuant to section 43-02-14-05.1.

20.Identify whether the area of review extends across state jurisdiction boundary lines.

21.Address the potential for unrecoverable injected oil or gas.

22.Address enrichment of the injected gas by hydrocarbons native to the oil and gas reservoir.

23.The stimulation plan for all geological storage facility wells, if any, including a description of the stimulation fluids to be used, and a determination that the stimulation will not interfere with containment.

24.An emergency and remedial response plan pursuant to section 43-02-14-15.

25.A corrosion monitoring and prevention plan for all wells and surface facilities.

26.A leak detection and monitoring plan for all surface facilities.

27.A leak detection and monitoring plan to monitor any movement of the oil or gas outside of the geological storage reservoir. This may include monitoring wells and the collection of baseline information of oil or gas background concentrations in ground water, surface soils, and chemical composition of in situ waters within the oil or gas facility area, and its delineated area of review.

28.A time frame for extraction of injected oil or gas and expected recovery percentages.

29.Address associated water recovery and a plan for disposal.

30.Any additional information the director may require.

N.D. Admin. Code 43-02-14-07 Permit requirements - Storage in saline reservoir

An application for a geological storage facility permit must include at least the following:

2.Address surface and pore space ownership by filing the following:

a.An affidavit of mailing, including the name and address of each owner, certifying that all surface owners of record within the storage reservoir and one-half mile [.80 kilometer] adjacent have been notified of the proposed geological storage project.

b.An affidavit of mailing, including the name and address of each owner, certifying that all pore space owners and pore space lessees of record within the storage reservoir and one-half mile [.80 kilometer] adjacent have been notified of the proposed geological storage project.

c.Legal descriptions of surface ownership of record within the storage reservoir and one-half mile [.80 kilometer] adjacent.

d.Legal descriptions of pore space owners and pore space lessees of record within the storage reservoir and one-half mile [.80 kilometer] adjacent.

3.Applicant shall request a permit for all oil or gas injection wells, monitoring wells, and surface facilities by filing the following:

a.Application for permit to drill filed on a form provided by the director pursuant to chapter 43-02-03; and

b.Application for permit to inject filed on a form provided by the director, including at least the following:

(1)The name and address of the operator of the injection well.

(2)The estimated bottom hole fracture pressure of the upper confining zone.

(3)Average maximum daily rate of oil or gas to be injected.

(4)Average and maximum requested surface injection pressure.

(5)Geological name and depth to base of the lowermost underground source of drinking water which may be affected by the injection.

(6)Existing or proposed casing, tubing, and packer data.

(7)Existing or proposed cement specifications, including amounts and actual or proposed top of cement.

(8)A plat and maps depicting the area of review, based on the associated geological storage facility permit, and detailing the location, well name, and operator of all wells in the area of review. The plat and maps must include all injection wells, producing wells, plugged wells, abandoned wells, drilling wells, dry holes, permitted wells, water wells, surface bodies of water, and other pertinent surface features, such as occupied dwellings and roads.

(9)A review of the surficial aquifers within one mile [1.61 kilometer] of the proposed injection well site or surface facilities.

(10)Proposed injection program, including method of transportation of the oil or gas to the injection facility and the injection well.

(11)List identifying all source wells or sources of injectate.

(12)All logging and testing data on the well which has not been previously submitted.

(13)Schematic or other appropriate drawings and tabulations of the wellhead and surface facilities, including the size, location, construction, and purpose of all tanks, the height and location of all dikes and containment, including a calculated containment volume, all areas underlain by a synthetic liner, the location of all flow lines, and a tabulation of any pressurized flow line specifications. It must also include the proposed road access to the nearest existing public road and the

authority to build such access.

(14)A schematic drawing of the well detailing the proposed well bore construction, including the size of the borehole; the total depth and plug back depth; the casings and tubing sizes, weights, grades, and top and bottom depths; the perforated interval top and bottom depths; the packer depth; the injection zone; and upper and lower confining zones top and bottom depths.

(15)A detailed description of the proposed completion or conversion procedure, including any proposed well stimulation.

(16)Any other information required by the director to evaluate the proposed well.

4.A map showing the extent of the pore space that will be occupied by the injection and

5.A map showing the outside boundary of the oil or gas facility area, its delineated area of review, and the surface and bottom hole location of all proposed injection wells, monitoring

6.Structural and stratigraphic cross sections that describe the geological conditions of the geological storage reservoir.

7.A structure map of the top and base of the geological storage reservoir.

8.An isopach map of the geological storage reservoir.

9.Identification of all structural spill points or stratigraphic discontinuities controlling the isolation of stored oil or gas and associated fluids within the geological storage reservoir.

10.Geomechanical information sufficient to demonstrate that the confining zone is free of transmissive faults or fractures and of sufficient areal extent and integrity to contain the injected oil or gas stream.

11.Any known regional or local faulting. If faults are known or suspected, a cross section that

12.A method for delineating the area of review, including the computational model to be used, assumptions that will be made, and the site characterization data on which the model will be

13.A map of all wells, including all injection wells, producing wells, plugged wells, abandoned wells, drilling wells, dry holes, water wells, and other subsurface structures within the oil or gas

14.A determination that all abandoned wells have been properly plugged and all operating wells have been constructed in a manner that prevents the oil or gas or associated fluids from escaping the geological storage reservoir.

15.A tabular description and well bore diagram of each well's type, construction, date drilled,

16.Quantitative analysis from a state-certified laboratory of freshwater from all available freshwater wells within the oil or gas facility area and its delineated area of review. The location of all wells by quarter-quarter, section, township, and range must also be submitted.

This requirement may be waived by the director in certain instances.

17.Quantitative analysis from a third-party laboratory of a representative sample of the oil or gas to be injected. A compatibility analysis with the receiving formation may also be required.

18.A map showing all occupied dwellings within the oil or gas facility area, including the delineated area of review.

19.Corrective action plan pursuant to section 43-02-14-05.1.

20.Identify whether the area of review extends across state jurisdiction boundary lines.

21.Address the potential for migration of unrecoverable injected oil or gas.

22.The stimulation plan for all geological storage facility wells, if any, including a description of the stimulation fluids to be used, and a determination that the stimulation will not interfere with containment.

23.An emergency and remedial response plan pursuant to section 43-02-14-15.

24.A corrosion monitoring and prevention plan for all wells and surface facilities.

25.A leak detection and monitoring plan for all surface facilities.

26.A leak detection and monitoring plan to monitor any movement of the oil or gas outside of the geological storage reservoir. This may include monitoring wells and the collection of baseline information of oil or gas background concentrations in ground water, surface soils, and chemical composition of in situ waters within the oil or gas facility area, its delineated area of review.

27.A time frame for extraction of injected oil or gas and expected recovery percentages.

28.Address associated water recovery and a plan for disposal.

29.Any additional information the director may require.

N.D. Admin. Code 43-02-14-08 Permit requirements - Storage in salt cavern

An application for a geological storage facility permit must include at least the following:

2.Address surface, pore space, and salt mineral ownership by filing the following:

a.An affidavit of mailing, including the name and address of each owner, certifying that all surface owners of record within the salt cavern and one-half mile [.80 kilometer] adjacent have been notified of the proposed geological storage project.

b.An affidavit of mailing, including the name and address of each owner, certifying that all salt mineral lessees, salt mineral owners of record, pore space owners and pore space lessees of record within the salt cavern and one-half mile [.80 kilometer] adjacent have been notified of the proposed geological storage project.

c.Legal descriptions of surface ownership of record within the salt cavern and one-half mile [.80 kilometer] adjacent.

d.Legal descriptions of salt mineral lessees and salt mineral owners of record within the salt cavern and one-half mile [.80 kilometer] adjacent.

e.Legal descriptions of pore space owners and pore space lessees of record within the salt cavern and one-half mile [.80 kilometer] adjacent.

3.Applicant shall request a permit for all oil or gas injection wells, monitoring wells, and surface facilities by filing an application for permit to inject filed on a form provided by the director, including at least the following:

a.The name and address of the operator of the injection well.

b.The estimated bottom hole fracture pressure of the upper confining zone.

c.Average maximum daily rate of oil or gas to be injected.

d.Average and maximum requested surface injection pressure.

e.Current capacity and geometry of the cavern.

f.Tools used to confirm capacity and geometry of cavern.

g.Current thickness of remaining salt at top and bottom of cavern.

h.Geological name and depth to base of the lowermost underground source of drinking water which may be affected by the injection.

i.Existing or proposed casing, tubing, and packer data.

j.Existing or proposed cement specifications, including amounts and actual or proposed top of cement.

k.A plat and maps depicting the area of review, based on the associated geological storage facility permit, and detailing the location, well name, and operator of all wells in the area of review. The plat and maps must include all injection wells, producing wells, plugged wells, abandoned wells, drilling wells, dry holes, permitted wells, water wells, surface bodies of water, and other pertinent surface features, such as occupied dwellings and roads.

l.A review of the surficial aquifers within one mile [1.61 kilometer] of the proposed injection well site or surface facilities.

m.Proposed injection program, including method of transportation of the oil or gas to the injection facility and the injection well.

n.List identifying all source wells or sources of injectate.

o.All logging and testing data on the well which has not been previously submitted.

p.Schematic or other appropriate drawings and tabulations of the wellhead and surface facilities, including the size, location, construction, and purpose of all tanks, the height and location of all dikes and containment, including a calculated containment volume, all areas underlain by a synthetic liner, the location of all flow lines, and a tabulation of any pressurized flow line specifications. It must also include the proposed road access to the nearest existing public road and the authority to build such access.

q.A schematic drawing of the well detailing the proposed well bore construction, including the size of the borehole; the total depth and plug back depth; the casings and tubing sizes, weights, grades, and top and bottom depths; the perforated interval top and bottom depths; the packer depth; the injection zone; and upper and lower confining zones top and bottom depths.

r.A detailed description of the proposed completion or conversion procedure.

s.Any other information required by the director to evaluate the proposed well.

4.Anticipated capacity and geometry of the cavern.

5.Minimum and maximum capacity of the cavern to be utilized.

6.Tools used to confirm capacity and geometry of the cavern.

7.Current thickness of remaining salt at the top and bottom of the cavern.

8.Description and schematics for brine management at the surface.

9.Description of measures in place to prevent unintended flowback.

10.A map showing the extent of the pore space that will be occupied by the injection and

11.A map showing the outside boundary of the oil or gas facility area, its delineated area of review, and the surface and bottom hole location of all proposed injection wells, monitoring

12.Structural and stratigraphic cross sections that describe the geological conditions of the salt cavern.

13.A structure map of the top and base of the salt formation being utilized.

14.An isopach map of the salt formation being utilized.

15.Geomechanical analysis of the cavern used to determine cavern stability, using the following:

a.Geological characteristics.

b.Petrophysical properties.

c.Rock mechanical properties.

d.In situ stresses.

e.Any other input data acquired and utilized.

16.Address the following cavern stability issues at minimum:

a.Salt creep and mitigation measures.

b.Minimum salt roof thickness.

c.Roof collapse.

d.Maximum cavern diameter.

e.Spacing between offsetting caverns.

f.Minimum setback for drilling in the vicinity.

g.Salt thinning due to any stratigraphic change.

h.Any dissolution zones in the salt.

i.Minimum operating pressures and capacity volumes, roof geometry, and height/diameter ratios used to prevent any of the above or other pertinent stability issues.

17.Any known regional or local faulting. If faults are known or suspected, a cross section that

18.A method for delineating the area of review, including the geomechanical model to be used, assumptions that will be made, and the site characterization data on which the model will be

19.A map of all wells, including all injection wells, producing wells, plugged wells, abandoned wells, drilling wells, dry holes, water wells, and other subsurface structures within the oil or gas

20.A determination that all abandoned wells have been properly plugged and all operating wells have been constructed in a manner that prevents the oil or gas or associated fluids from escaping the salt cavern.

21.A tabular description and well bore diagram of each well's type, construction, date drilled,

22.Quantitative analysis from a state-certified laboratory of freshwater from all available freshwater wells within the geological storage facility. The location of all wells by quarter-quarter, section, township, and range must also be submitted. This requirement may be waived by the director in certain instances.

23.Quantitative analysis from a third-party laboratory of a representative sample of the oil or gas to be injected. A compatibility analysis with the receiving formation may also be required.

24.A map showing all occupied dwellings within the oil or gas facility area, including the delineated area of review.

25.Corrective action plan pursuant to section 43-02-14-05.1.

26.Identify whether the area of review extends across state jurisdiction boundary lines.

27.An emergency and remedial response plan pursuant to section 43-02-14-15.

28.A corrosion monitoring and prevention plan for all wells and surface facilities.

29.A leak detection and monitoring plan for all surface facilities.

30.A leak detection and monitoring plan to monitor any movement of the oil or gas outside of the salt cavern. This may include monitoring wells and the collection of baseline information of oil or gas background concentrations in ground water, surface soils, and chemical composition of in situ waters within the oil or gas facility area and its delineated area of review.

31.Any additional information the director may require.

N.D. Admin. Code 43-02-14-09 Siting

All injection wells must be sited in such a fashion that they inject into a formation which has confining zones that are free of known open faults or fractures within the facility area and its delineated area of review.

N.D. Admin. Code 43-02-14-10 Construction requirements

1.All injection wells must be cased and cemented to prevent movement of fluids into or between underground sources of drinking water or into an unauthorized zone. The casing and cement used in construction of each new injection well must be designed for the life expectancy of the well. All wells used for injection into a storage reservoir or salt cavern must have surface casing set and cemented at a point not less than fifty feet [15.24 meters] below the base of the Fox Hills formation. In determining and specifying casing and cementing requirements, all the following factors must be considered:

a.Depth to the injection zone and lower confining zone, or salt cavern specifics. Long string casing must be set at least to the top of the injection zone and cemented as approved by the director.

b.Depth to the bottom of all underground sources of drinking water.

c.Estimated minimum, maximum, and average injection pressures.

d.Fluid pressure.

e.Estimated fracture pressures.

f.Physical and chemical characteristics of the injection zone.

2.Appropriate logs and other tests must be conducted during the drilling and construction of injection wells. Any well drilled or converted to an injection well must have a cement bond log from which a presence of channels and microannulus can be determined radially. Cement bond logs must contain elements approved by the director.

3.After an injection well has been completed, approval must be obtained on a sundry notice filed on a form provided by the director before any subsequent perforating.

N.D. Admin. Code 43-02-14-11 Mechanical integrity

1.An injection well has mechanical integrity if:

a.There is no significant leak in the casing, tubing, or packer; and

b.There is no significant fluid movement into an underground source of drinking water through channels adjacent to the well bore.

2.One of the following methods must be used to evaluate the absence of significant leaks:

a.Pressure test with liquid or gas.

b.Monitoring of positive annulus pressure following a valid pressure test.

c.Radioactive tracer survey.

3.On a schedule determined by the commission, the storage facility operator shall use one or more of the following methods to determine the absence of significant fluid or gas movement:

a.A cement bond log from which a presence of channels and micro annulus can be determined radially.

b.A temperature log.

c.Any alternative testing method that provides equivalent or better information and that the director requires or approves.

4.The operator of an injection well immediately shall shut in the well if mechanical failure indicates fluids are, or may be, migrating into an underground source of drinking water or an unauthorized zone, or if so directed by the director.

N.D. Admin. Code 43-02-14-12 Plugging of injection wells

The proper plugging of an injection well requires the well be plugged with cement or other types of plugs, or both, in a manner which will not allow movement of fluids into an underground source of drinking water. The operator shall file a notice of intention to plug on a form provided by the director and shall obtain the director's approval of the plugging method before the commencement of plugging operations.

N.D. Admin. Code 43-02-14-13 Pressure restrictions

1.The following applies to geological storage in an oil and gas reservoir or saline reservoir:

a.Injection pressure at the wellhead may not exceed a maximum authorized injection pressure which must be calculated to assure that the pressure in the storage reservoir during injection does not initiate new fracture or propagate existing fractures in the confining zones.

b.In no case may injection pressure initiate fractures in the confining zones or cause the movement of injection or formation fluids into an unauthorized zone or underground source of drinking water.

2.The following applies to geological storage in a salt cavern:

a.A minimum operating pressure protective of the cavern's integrity must be maintained.

b.A maximum allowable operating pressure must be established based on the casing seat or the highest elevation of the cavern's roof, whichever is higher in elevation. 43-02-14-13.1. Salt cavern integrity.

The operator shall execute the emergency and remedial response plan pursuant to section 43-02-14-15 in the event of loss of integrity in the storage cavern for any reason.

N.D. Admin. Code 43-02-14-14 Bonding requirements

All storage facilities, injection wells, and monitoring wells must be bonded as provided in section 43-02-03-15.

N.D. Admin. Code 43-02-14-15 Emergency and remedial response plan

The storage facility operator shall maintain a commission approved emergency and remedial response plan. This plan must include emergency response and security procedures. The plan, including revision of the list of contractors and equipment vendors, must be updated as necessary or as the commission requires. Copies of the plans must be available at the storage facility and at the storage facility operator's nearest operational office.

1.The emergency and remedial response plan requires a description of the actions the storage facility operator shall take to address movement of the injection or formation fluids that may endanger an underground source of drinking water during any phase of the project. The requirement to maintain and implement a commission-approved plan is directly enforceable regardless of whether the requirement is a condition of the permit. The plan must also detail:

a.The safety procedures concerning the facility and residential, commercial, and public land use within the facility area and its delineated area of review.

b.Contingency plans for addressing oil or gas leaks from any well, flow lines, or other facility, and loss of containment from the storage reservoir or salt cavern and identify specific contractors and equipment vendors capable of providing necessary services and equipment to respond to such leaks or loss of containment.

2.If the storage facility operator obtains evidence that the injected oil or gas stream, or displaced fluids may endanger an underground source of drinking water, the storage facility operator shall:

a.Immediately cease injection.

b.Take all steps reasonably necessary to identify and characterize any release.

c.Notify the director immediately and submit a subsequent sundry notice filed on a form provided by the director within twenty-four hours.

d.Implement the emergency and remedial response plan approved by the director.

3.The commission may allow the operator to resume injection before remediation if the storage facility operator demonstrates that the injection operation will not endanger underground sources of drinking water.

4.The storage facility operator shall review annually the emergency and remedial response plan developed under subsection 1. Any amendments to the plan are subject to the commission's approval, must be incorporated into the storage facility permit, and are subject to the permit modification requirements. Amended plans or demonstrations that amendments are not needed must be submitted to the commission as follows:

a.With the area of review re-evaluation.

b.Following any significant changes to the facility, such as addition of injection or monitoring wells, or on a schedule determined by the commission.

c.When required by the commission.

N.D. Admin. Code 43-02-14-16 Reporting, monitoring, and operating requirements

1.The operator of a storage facility shall meter or use an approved method to keep records and shall report monthly to the director, the volume and nature of the injected hydrocarbons, the average, minimum, and maximum injection pressures, the maximum injection rates, and such other information as the director may require. The operator of each storage facility shall, on or before the fifth day of the second month succeeding the month in which the well is capable of injection, file with the director the aforementioned information for the storage facility in a format provided by the director.

2.Immediately upon the commencement or recommencement of injection, the operator shall notify the director of the injection date verbally and in writing.

3.The operator shall place accurate gauges on the tubing and the tubing casing annulus of all injection wells utilized in the storage facility. Accurate gauges must also be placed on any other annuluses deemed necessary by the director.

4.The operator of a storage facility shall keep the wells, surface facilities, and injection system under continuing surveillance and conduct such monitoring, testing, and sampling as the director may require verifying the integrity of the surface facility, gathering system, and injection wells to protect surface and subsurface waters. Before commencing operations, the injection pipeline must be pressure tested. All existing injection pipelines where the pump and the wellhead are not located on the same site are required to be pressure tested annually.

5.The operator of a storage facility shall report any noncompliance with regulations or permit conditions to the director verbally within twenty-four hours followed by a written explanation within five days. The operator shall cease injection operations if so directed by the director.

6.Within ten days after the discontinuance of injection operations, the operator shall notify the director of the date of such discontinuance and the reason therefor.

7.Upon the completion or recompletion of an injection well or the completion of any remedial work or attempted remedial work, such as plugging back, deepening, acidizing, shooting, formation fracturing, squeezing operations, setting liner, perforating, reperforating, tubing repairs, packer repairs, casing repairs, or other similar operations not specifically covered herein, a report on the operation must be filed with the director within thirty days. The report must present a detailed account of all work done, including the reason for the work, the date of such work, the shots per foot and size and depth of perforations, the quantity of sand, crude, chemical, or other materials employed in the operation, the size and type of tubing, the type and location of packer, the result of the packer pressure test, and any other pertinent information or operations which affect the status of the well and are not specifically covered herein.

8.Annular injection of fluids is prohibited.

N.D. Admin. Code 43-02-14-17 Leak detection and reporting

1.Leak detection must be integrated, where applicable and must be inspected and tested on a semiannual basis and, if defective, must be repaired or replaced within ten days. Any repaired or replaced detection equipment must be retested if required by the commission. An extension of time for repair or replacement of leak detection equipment may be granted upon a showing of good cause by the storage facility operator. A record of each inspection must include the inspection results and be maintained by the operator at least until project completion, and must be made available to the commission upon request.

2.Pursuant to section 43-02-03-30 the storage facility operator shall immediately report to the commission any leak detected at any well or surface facility.

3.The storage facility operator immediately shall report to the commission any pressure changes or other monitoring data from subsurface observation wells or injection wells that indicate the presence of leaks in the storage reservoir or salt cavern.

4.The storage facility operator immediately shall report to the commission any other indication that the storage facility is not containing oil, gas, or brine, whether the lack of containment concerns the storage reservoir or salt cavern, surface equipment, or any other aspect of the storage facility.

N.D. Admin. Code 43-02-14-18 Storage facility permit transfer

1.The storage operator and proposed transferee shall notify the commission in writing of any proposed permit transfer. The notice must contain the following:

a.The name and address of the person to whom the permit is to be transferred.

b.The name of the permit subject to transfer and location of the storage facility and a description of the land within the facility area.

c.The date that the storage operator desires the proposed transfer to occur.

d.Meet the bonding requirements of section 43-02-14-14.

2.A transfer may only take place after notice and hearing. The transferee shall demonstrate that all requirements of chapter 43-02-14 are complied with. The transferee shall outline necessary permit modifications based on operational changes, if any.

3.Commission review. The commission shall review the proposed transfer to ensure that the purposes of North Dakota Century Code chapter 38-25 are not compromised but are promoted. For good cause, the commission may deny a transfer request, delay on acting on it, and place conditions on its approval.

4.Commission approval required. A permit transfer may occur only upon the commission's written order. The transferor of a permit shall receive notice from the commission that the approved new storage facility operator has met the bonding requirements of section 43-02-14-14.

N.D. Admin. Code 43-02-14-19 Modification, revocation, and reissuance or termination of permits

1.Permits are subject to review by the commission. Any interested person (i.e., the storage operator, local governments having jurisdiction over land within the area of review, and any person who has suffered or will suffer actual injury or economic damage) may request that the commission review permits issued under this chapter for one of the reasons set forth below.

All requests must be in writing and must contain facts or reasons supporting the request. If the commission determines that the request may have merit or at the commission's initiative for one or more of the reasons set forth below, the commission may schedule a hearing to review the permit and thereafter issue an order modifying or revoking the permit. Permits, after notice and hearing, may be modified or revoked and reissued when the commission determines one of the following events has occurred:

a.Changes to the facility area.

b.Area of review or corrective action re-evaluations pursuant to section 43-02-14-05.1.

c.Operating outside of parameters of the permit of section 43-02-14-06, 43-02-14-07, or 43-02-14-08, whichever is applicable.

d.Amendment to the emergency and remedial response plan of section 43-02-14-15.

e.Amendment to the leak detection plan of section 43-02-14-17.

f.Review of monitoring and testing results conducted in accordance with injection well permit requirements.

g.The commission receives information that was not available at the time of permit issuance. Permits may be modified during their terms for this cause only if the information was not available at the time of permit issuance, other than revised regulations, guidance, or test methods, and would have justified application of different permit conditions at the time of the issuance.

h.The standards or regulations on which the storage facility permit was based have been changed by promulgation of new or amended standards or regulations or by judicial decision after the permit was issued.

i.The commission determines good cause exists for modification of a compliance schedule, such as an act of God, strike, flood, or materials shortage or other events over which the storage operator has little or no control and for which there is no reasonably available remedy.

j.There are material and substantial additions to the permitted facility or activity which occurred after permit issuance which justify the application of permit conditions that are different or absent in the existing permit.

2.If the commission tentatively decides to modify or revoke and reissue a permit, the commission shall incorporate the proposed changes to the original permit. The commission may request additional information and, in the case of a modified permit, may require the submission of an updated application. In the case of a revoked and reissued permit, the commission shall require the submission of a new permit application.

3.In a permit modification under this section, only those conditions to be modified may be reopened when a revised permit is prepared. All other aspects of the existing permit remain in effect for the duration of the unmodified permit. When a permit is revoked and reissued, the entire permit is reopened just as if the permit had expired and was being reissued. During any revocation and reissuance proceeding, the storage operator shall comply with all conditions of the existing permit until a new final permit is reissued.

4.Suitability of the storage facility location may not be considered at the time of a permit modification or revocation unless new information or standards indicate that a threat to human health or the environment exists which was unknown at the time of permit issuance.

5.The following are causes for terminating an injection well permit during its term:

a.Noncompliance by the storage operator with any permit condition.

b.Failure by the storage operator to fully disclose all relevant facts or misrepresentation of relevant facts to the commission.

c.A determination that the permitted activity endangers human health or the environment.

6.If the commission tentatively decides to terminate a permit, the commission shall issue notice of intent to terminate. 43-02-14-19.1. Minor modifications of permit.

Upon agreement between the storage facility operator and the commission, the commission may modify a permit to make the corrections or allowances without the storage operator filing an application to amend a permit. Any permit modification not processed as a minor modification under this section must be filed as an application to amend an existing permit under section 43-02-14-18. Minor modifications may include:

1.Correct typographical errors.

2.Require more frequent monitoring or reporting by the storage operator.

3.Change quantities or types of fluids or gases injected which are within the capacity of the facility as permitted and, in the judgement of the commission, would not interfere with the operation of the facility or its ability to meet conditions described in the permit and would not change its classification.

4.Change construction requirements approved by the commission, provided that any such alteration must comply with the requirements of this chapter and no such changes are physically incorporated into construction of the well before approval of the modification by the commission.

5.Amending any of the plans of this chapter where the modifications merely clarify or correct the plan, as determined by the commission.

Chapter 43-02-15 Certification of Restimulation Wells

N.D. Admin. Code 43-02-15-01 Definitions

The terms used throughout this chapter have the same meaning as in chapter 43-02-03 and North Dakota Century Code chapters 38-08 and 57-51.1.

N.D. Admin. Code 43-02-15-02 Application to certify a restimulation well

Any operator desiring to certify a restimulation well for purposes of eligibility for the tax reduction provided in North Dakota Century Code chapter 57-51.1 shall submit to the director an application for certification of the restimulation well. The operator has the burden of establishing entitlement to the certification and shall submit all data necessary to enable the director to determine whether the well should be certified as a restimulation well and entitled to the tax reduction provided in North Dakota Century Code section 57-51.1-03.

The application must be on a well sundry form and include the following:

1.The name and address of the operator of the restimulation well, including the phone number and electronic mail address of the submitting representative.

2.The well name and number, file number, and legal description of the surface location of the well by quarter-quarter, section, township, range, and county for which the certification is requested.

3.The field and pool for the well the restimulation was performed in for which the certification is requested.

4.The legal description of the spacing unit for the pool in the well the restimulation was performed in for which the certification is requested.

5.The original completion date for the pool in the well the restimulation was performed in for which the certification is requested.

6.The date previous stimulations were performed in pool in the well the restimulation was performed in for which the certification is requested.

7.A copy of the completion report for the pool in the well the restimulation was performed in for which the certification is requested, including the restimulation date and details.

8.Calculated barrels of oil per day for the most recent reporting month during which the restimulation well was produced at a maximum efficient rate for the pool in the well the restimulation was performed in for which the certification is requested.

9.Certification by the operator that:

a.The restimulation well is not located within the exterior boundaries of a reservation, is not located on trust properties outside a reservation boundary as defined in North Dakota Century Code section 57-51.2-02, and is not a straddle well located on reservation trust land as defined in North Dakota Century Code section 57-51.1-07.10, unless a tribe has made an irrevocable election to opt-in to the tax reduction by providing written notice to the tax commissioner. A copy of such notice shall be included.

b.The restimulation well is not a qualified stripper well or part of a qualified stripper well property as defined in North Dakota Century Code section 57-51.1-01.

c.The restimulation well is not part of a qualifying secondary recovery project or qualifying tertiary recovery project as defined in North Dakota Century Code section 57-51.1-01.

The application for certification must be accompanied by sufficient documentation for the director to determine the restimulation well constitutes a well as specified in North Dakota Century Code section 57-51.1-01. If the application does not contain sufficient information to make a determination, the director may require the operator to submit additional information.

N.D. Admin. Code 43-02-15-03 Director certification of a restimulation well

1.Upon receipt of an application for restimulation well certification, the director shall review the application, information, and all relevant information contained in the books, files, and records of the commission.

2.Restimulation well certification must be determined on the basis of the qualified calculated maximum barrels of oil per day for the most recent reporting month prior to the restimulation operation during which the restimulation well was produced at a maximum efficient rate for the pool in the well the restimulation was performed in. To qualify production from a restimulation well for the calculated barrels of oil per day, the restimulation well must have been maintained at the maximum efficient rate of production or is not capable of exceeding the production threshold if the well had been maintained at the maximum efficient rate of production throughout the qualifying reporting month.

3.Within thirty days of the receipt of a complete application for restimulation well certification, or a reasonable time thereafter, the director shall either grant or deny the application.

4.If an application for restimulation well certification is denied, the director shall enter a written determination denying the application and specify the basis for the denial. If an application for restimulation well certification is granted, the director shall enter a written determination granting the application and forward a copy to the tax commissioner. A copy of the determination either granting or denying the restimulation well certification application must be forwarded by the director to the operator. It is the obligation of the operator to notify and advise all other owners in the well and the purchaser of the crude oil of the determination of the director.

N.D. Admin. Code 43-02-15-04 Operator adversely affected may submit amended application - Procedure

Any operator adversely affected by a determination of the director made under this chapter may submit an amended application within thirty days after the entry of such a determination. If an amended application is submitted, the director shall issue a determination either granting or denying the restimulation well certification within thirty days of the receipt of the amended application or a reasonable time thereafter.

N.D. Admin. Code 43-02-15-05 Operator adversely affected may petition the commission - Procedure

Any operator adversely affected by a determination of the director of either an application or an amended application for restimulation well certification made under this chapter may petition the commission within thirty days after the entry of such a determination for a hearing in accordance with the provisions of North Dakota Century Code chapter 38-08 and chapter 43-02-03.

N.D. Admin. Code 43-02-15-06 Books and records to be kept to substantiate reports

Any operator making application to certify a restimulation well pursuant to this chapter shall make and keep records for a period of not less than six years, covering their operations in North Dakota from which they may be able to make and substantiate the reports required by this chapter.

Article 43-03 Contracts for Land Reclamation Research and Research, Development, and Marketing of Lignite Products Derived from Lignite

Chapter 43-03-01 General Provisions

N.D. Admin. Code 43-03-01-01 History - Administration

Since 1987 the North Dakota industrial commission has been authorized to make funds available to provide financial assistance for contracts for land reclamation research projects and for research, development, and marketing of lignite and products derived from lignite. The lignite research council, established by executive order 1987-4, and as presently constituted by executive order 1991-1, will review and make recommendations to the commission on all applications for financial assistance under this program. The industrial commission concurred in the appointments to the lignite research council.

History

• History: Effective February 1, 1988; amended effective October 1, 1990; March 1, 1992.
• Law Implemented: NDCC 54-17.5-01, 57-61-01.5

N.D. Admin. Code 43-03-01-02 Definitions

As used in this article:

1."Applicant" means any person or entity applying to the commission for a grant from the lignite research fund.

2."Application" means the written document that is submitted to the commission by an applicant seeking a grant from the fund.

3."Commission" means the North Dakota industrial commission or its representative.

4."Contract" means the signed agreement between the commission and grantee which describes the rights and duties of the commission and grantee with regard to the program.

5."Council" means the lignite research council.

6."Executive committee" means a committee of the council.

7."Fund" means the lignite research fund available to the commission to provide funding for the program.

8."Grant" means the monetary award made by the commission under the program.

9."Grantee" means a successful applicant for a grant from the fund.

10."Program" means the program administered by the commission to provide financial assistance from the fund for land reclamation research projects and for research, development, and marketing of lignite and products derived from lignite.

11."Technical review committee" means a committee or committees selected by the commission to review the merits of applications and to otherwise assist the commission in administering the program.

History

• History: Effective February 1, 1988; amended effective October 1, 1990; March 1, 1992.

N.D. Admin. Code 43-03-01-03 Costs of application preparation

The commission is not liable for any cost, including costs of preparation of applications, incurred by applicants prior to issuance of a contract. The commission will be liable only for those costs and expenses expressly identified by contract.

History

• History: Effective February 1, 1988.

N.D. Admin. Code 43-03-01-04 Acceptance and rejection of applications

The rules in this article do not commit the commission to award funds. The commission reserves the right to accept or reject any or all applications received as a result of the program and to negotiate with any and all qualified applicants.

History

• History: Effective February 1, 1988; amended effective October 1, 1990; March 1, 1992.

N.D. Admin. Code 43-03-01-05 Reservation of funds

The commission is not obligated to award the total amount of funds made available under this program. Funds not awarded will be reserved for future grants under the program.

History

• History: Effective February 1, 1988; amended effective March 1, 1992.

N.D. Admin. Code 43-03-01-06 Statement of intent

Repealed effective March 1, 1992.

Chapter 43-03-02 Eligibility

N.D. Admin. Code 43-03-02-01 Eligible applicants

Any person, corporation, partnership, cooperative, or association, or consortium of such parties, may apply for funds under this program. With regard to site-specific feasibility studies, only owners of facilities, sponsors of projects, or operators having effective control of a facility or project may apply.

Applicants who do not own or control or have the clear and firm commitment of ownership or control are ineligible for feasibility study assistance. Any interested person in doubt as to eligibility should contact the commission.

History

• History: Effective February 1, 1988; amended effective March 1, 1992.
• General Authority: NDCC 57-61-01.5
• Law Implemented: NDCC 54-17.5-04, 57-61-01.5

N.D. Admin. Code 43-03-02-02 Eligible and ineligible projects

Any project proposing research, development, or marketing of lignite or products derived from lignite, or a land reclamation research project is eligible for a contract under this program. The following are examples of eligible topics:

1.Eligible lignite research projects include, but are not limited to:

a.Conversions of lignite to other products and byproducts.

b.Lignite cleaning or beneficiation.

c.Lignite desulfurization and emission control.

d.Lignite-water mixtures or lignite-methanol mixtures and other lignite-derived fuels.

e.Lignite-based cogeneration projects.

f.Development of markets for liquids or other byproducts derived from lignite.

g.Research and development of products using ash derived from lignite.

h.Studies of legal, regulatory, and economic factors affecting lignite use and development.

i.Development of materials for use in lignite market promotion.

j.Development of commercial programs to treat effluent, emissions, solid waste, or hazardous waste from lignite conversion plants, chemical spills and oil spills, using bioremediation technology.

k.Resource characterization and evaluation studies.

l.Development, demonstration, and refinement of gasification and liquefaction technologies using lignite.

m.Development of advanced combustion systems, that is, systems with high efficiency and low emissions.

n.In general, any project which will utilize or enhance the development or use of lignite resources.

2.Eligible land reclamation research projects include, but are not limited to:

a.Prime farmland soil productivity research.

b.Development of productivity indices for reclaimed land.

c.Soil respreading, depth of soil replacement, and compaction studies.

d.Research relating to root zone hydrology, runoff, and erosion on reclaimed land.

e.Other projects that may reduce unnecessary regulatory costs and assist in effectively reclaiming mined land to its original or better productivity.

3.The following activities or uses are ineligible for funding under this program:

a.Business startup capital.

b.Business working capital.

c.Business advertising or promotional expenses pertaining to a specific company or cooperative.

History

• History: Effective February 1, 1988; amended effective October 1, 1990; March 1, 1992.
• General Authority: NDCC 57-61-01.5
• Law Implemented: NDCC 54-17.5-01, 57-61-01.5

Chapter 43-03-03 Maximum Grant Amount and Matching Fund Requirement

N.D. Admin. Code 43-03-03-01 Maximum grant amount

Grants may be of any amount within the limits of legislative appropriation.

History

• History: Effective February 1, 1988; amended effective March 1, 1992.
• General Authority: NDCC 57-61-01.5
• Law Implemented: NDCC 54-17.5-04, 57-61-01.5

N.D. Admin. Code 43-03-03-02 Matching funds

A grant may not exceed fifty percent of the total project cost. Documentation demonstrating the matching funds, including letters of commitment from other funding sources, must be submitted to the commission within sixty days of the approval of an application by the commission, or within any additional time granted by the commission. The commission's approval is contingent upon receiving this documentation. If it is not received, the approval lapses and no grant may be made. Indirect costs (contributed equipment, materials, or services) may be used by any applicant to supply the required funding match or contribution.

History

• History: Effective February 1, 1988; amended effective October 1, 1990; March 1, 1992.
• General Authority: NDCC 57-61-01.5
• Law Implemented: NDCC 54-17.5-03, 54-17.5-04, 57-61-01.5

Chapter 43-03-04 Application Requirements

N.D. Admin. Code 43-03-04-01 Application format

An application must be direct, concise, and informative. It must be accompanied with the application fee set forth in section 43-03-04-03. It must be typed and double spaced on eight and one-half-inch by eleven-inch [21.59-centimeter by 27.94-centimeter] paper. Thirty-five copies of the application are to be submitted to the following address.

State of North Dakota The Industrial Commission State Capitol Bismarck, North Dakota 58505 ATTN: Lignite Research Program The application must contain the following:

1.Transmittal letter. A transmittal letter setting forth a binding commitment on behalf of the applicant to complete the project as described in the application if the commission makes the grant requested. The letter must be signed by someone authorized to contract on behalf of the applicant.

2.Title page. A title page setting forth the project title, applicant, principal investigator, date of application, and amount of the request.

3.Table of contents.

4.Abstract. A one-page abstract of the project stating its objective, expected results, duration, total project cost, and participants.

5.Project summary. An overview of the project that includes an explanation of its objectives.

The overview must include enough information to allow members of the technical review committee to determine if they are qualified to review the application.

6.Project description. A detailed description of the project, including its objectives; its methodology; its anticipated results; the facilities, resources, and techniques to be used and their availability and capability; the environmental and economic impacts of the project while it is underway; its ultimate technological and economic impacts; and why the project is needed.

7.Standards of success. The standards by which the success of the project is to be measured.

8.Background. A summary of prior work related to the project conducted by the applicant and other participants as well as by other organizations.

9.Qualifications. A summary of the experience and qualifications pertinent to the project of the applicant, principal investigator, and other participants in the project.

10.Value to North Dakota. An explanation of what parts of the public and private sector will likely make use of the project's results, and when and in what way; of the potential that commercial use will be made of the project's results; how the project will enhance the use of North Dakota lignite and lignite products; how it will preserve existing jobs and create new ones; and how it will otherwise satisfy the priorities established in North Dakota Century Code section 54-17.5-03.

11.Management. A description of how the applicant will manage and oversee the project to ensure it is being carried out on schedule and in a manner that best ensures its objectives will be met, and a description of the evaluation points to be used during the course of the project.

12.Timetable. A project schedule setting forth the starting and completion dates, dates for completing major project activities, and proposed dates upon which the interim reports required by section 43-03-05-08 will be submitted.

13.Budget. An itemized list of the project's capital costs; direct operating costs, including salaries; and indirect costs; and an explanation of which of these costs will be supported by the grant and in what amount. An explanation why the funding requested is necessary to achieve the project's objectives and, if less funding is available than that requested, whether the project's objectives will be unattainable or delayed.

14.Matching funds. An identification of all other committed and prospective funding sources and the amount of funding from each source.

15.Tax liability. An affidavit stating that the applicant does not have an outstanding tax liability owed to the state of North Dakota or any of its political subdivisions.

16.Confidential information. Any information in the application that is entitled to confidentiality and which the applicant wants to be kept confidential should, if possible, be placed in an

appendix to allow for administrative ease in protecting the information from public disclosure while allowing public access to the rest of the application. Such information must be clearly labeled as confidential and the applicant must explain why the information is entitled to confidentiality.

17.Appendices. Any necessary supporting documentation.

History

• History: Effective February 1, 1988; amended effective March 1, 1992.
• Law Implemented: NDCC 54-17.5-03, 54-17.5-04, 57-61-01.5

N.D. Admin. Code 43-03-04-02 Application deadline

Applications for the first review and award process in each fiscal year must be postmarked on or before October first, and applications for the second review and award process in each fiscal year must be postmarked on or before April first. In addition to these two grant rounds, the commission may establish additional grant rounds and set application deadlines for those rounds. The applicant may amend its application at any time before the application deadline. After the application deadline, the applicant may amend its application only upon the approval of the commission.

History

• History: Effective February 1, 1988; amended effective October 1, 1990; March 1, 1992.
• Law Implemented: NDCC 54-17.5-04, 57-61-01.5

N.D. Admin. Code 43-03-04-03 Application fee

All applications must be accompanied by a one hundred dollar nonrefundable application fee.

Checks or money orders should be made payable to the "State of North Dakota".

History

• History: Effective February 1, 1988.
• Law Implemented: NDCC 54-17.5-04, 57-61-01.5

N.D. Admin. Code 43-03-04-04 Outstanding tax liability

Superseded by subsection 15 of section 43-03-04-01, effective March 1, 1992.

Chapter 43-03-05 Review and Award Process

N.D. Admin. Code 43-03-05-01 Application evaluation - Criteria

All applications will be evaluated according to the criteria set forth in North Dakota Century Code

chapter 54-17.5, and the criteria established by the commission as stated in this section.

1.General criteria. Priority areas of the program include, but are not limited to, marketing applications of lignite and lignite products; reclamation applications that will reduce unnecessary regulatory costs; demonstration or development activities for lignite projects and activities and for lignite products that have a high probability of commercialization; and base-line research that promotes additional lignite production or lignite products for the economic growth of North Dakota. The project must be applicable to research, development, or marketing of lignite or products derived from lignite or land reclamation research. The projects need not be unique to North Dakota's lignite resources but must be applicable to them. It is preferred that the project focus on the development and use of lignite rather than basic research.

2.Specific criteria.

a.Projects should conform to the following criteria:

(1)Preserve or enhance existing jobs and create the opportunity for additional jobs.

(2)Preserve or enhance existing lignite production.

(3)Provide the opportunity for development and demonstration of marketable lignite products and technologies.

(4)Provide for economic growth and benefit in coal-producing counties or those counties with recoverable coal reserves.

(5)Provide a high probability for commercialization of the process, activity, or technology in North Dakota by the year 2000 or before.

(6)Provide for specific marketing strategies and contributions to the effective marketing of lignite, its products, or lignite-based technologies by the year 2000 or before.

(7)Provide opportunity for reclamation research projects that will reduce unnecessary regulatory costs and assist in effectively reclaiming surface mine land to its original or better productivity as soon as possible.

b.The merits of the project will be weighed in relation to:

(1)The potential value of the project's success including market potential, social value, environmental value, technical feasibility, competition in the marketplace, and timing of completion;

(2)The feasibility of the cost benefit ratio of the project;

(3)The risk involved in funding the project; and (4)The economic condition of the applicant.

c.The project's compatibility with the objectives of the program will be considered, in particular, the following will be evaluated:

(1)The need for the project;

(2)The potential use by the lignite-related industry of the results to be achieved by the project;

(3)The timeliness of the project with regards to deadlines established by legislation;

(4)The impact on the lignite-related industry;

(5)The level of funding requested;

(6)The level of matching funds;

(7)The short-term and long-term benefits to the applicant, lignite industry, lignite producers, and the counties and state of North Dakota;

(8)The likelihood that the project will achieve its technical and market goals;

(9)The scientific soundness and innovation of any proposed technology;

(10)The financial feasibility of the proposed project; and (11)The technical qualifications and expertise of the applicant, the investigators, and the sponsors.

History

• History: Effective February 1, 1988; amended effective October 1, 1990; March 1, 1992.
• Law Implemented: NDCC 54-17.5-01, 54-17.5-03, 57-61-01.5

N.D. Admin. Code 43-03-05-02 Application review - Initial review

Upon receipt of an application, the commission will determine if the application meets eligibility requirements and is complete. The commission shall complete this review within thirty days of the application deadline date, though the commission may extend this time if needed to properly review an application. If the commission determines that the application meets eligibility requirements and is complete, the application will be referred to a technical review committee. The commission may also refer any question it has about completeness and eligibility to the technical review committee and such question may then be a consideration throughout the review process.

1.Composition. Members of a technical review committee are selected by the commission.

Committee members should possess the expertise and experience necessary to adequately review the application.

2.Conflict of interest. No individual with a direct financial interest in a proposed project may be involved in any way in reviewing the application. If asked to review the application, the individual with the conflict of interest shall immediately inform the commission of the conflict.

Failure to so notify the commission disqualifies the individual from serving on any technical review committee unless reinstated by the commission, and the commission may disqualify the application from being approved during the round of grants within which the conflict occurred.

3.Review. The technical review committee shall assess the technical and fiscal merits of the application. Upon completion of its review, the committee shall make its recommendation to the council. The committee shall submit its recommendation within sixty days, though the commission may extend this time if the committee needs more time to properly review the application.

4.Notification to applicant. The commission shall promptly notify the applicant of the recommendation made by the committee to the council.

The council shall consider, but is not bound by, a recommendation of the technical review committee. The council shall make a recommendation on each application to the commission. The council shall make its recommendation to the commission within thirty days of its receipt of the technical review committee's recommendation, though the commission may extend this time if the council needs more time to properly review the application. The commission shall consider, but is not bound by, a recommendation of the council. Though the commission makes the decision to approve or reject all applications, the commission may only approve those applications that have received a favorable council recommendation.

History

• Law Implemented: NDCC 54-17.5-03, 54-17.5-04, 57-61-01.5 43-03-05-02.1. Application review - Technical review committee.
• Law Implemented: NDCC 54-17.5-03, 54-17.5-04, 57-61-01.5 43-03-05-02.2. Application review - Council recommendation and commission decision.
• Law Implemented: NDCC 54-17.5-02, 54-17.5-03, 54-17.5-04, 57-61-01.5

N.D. Admin. Code 43-03-05-03 Contracts

A grantee must enter into a contract with the commission and submit any supporting documentation required by the commission. The application will form an integral part of the contract. The commission shall provide a proposed contract to grantees within sixty days of commission approval of the project.

The grantee will then have sixty days to execute a contract. If a contract is not executed by the grantee within the sixty days, the award will be canceled unless an extension of time is granted by the commission. Work carried out under a contract is the work of the grantee and not the commission.

History

• History: Effective February 1, 1988; amended effective October 1, 1990; March 1, 1992.

N.D. Admin. Code 43-03-05-04 Disbursement of funds

Funds will be disbursed only after a contract has been executed. All disbursements will be made according tothe schedule in the contract. Disbursements may be withheld if the commission deems the grantee has not complied with these rules or the contract. 43-03-05-04.1. Project duration.

The project must be completed within the time specified in the contract. If the project cannot be completed within the time specified in the contract, the grantee may make a written request to the commission for an extension of up to one year. The request must set forth the specific additional time requested and the reasons why an extension is needed. Upon receipt of the request, the commission shall convey it to the council's executive committee. The executive committee may make use of a technical review committee to analyze the request. The executive committee shall review the request and make a recommendation to the commission. The commission, after reviewing the recommendation, shall decide whether or not to grant the request. Additional extensions may be sought under the same procedure described above, but may only be granted if the grantee proves that factors beyond the grantee's control are the cause of its inability to complete the project on time and that since receiving the first extension the grantee has been diligent in all respects in trying to complete the project on time.

N.D. Admin. Code 43-03-05-05 Allocations

If the work under a contract extends beyond the state's fiscal biennium in which the contract is made, any further disbursements of the grant by the commission to the grantee cannot be guaranteed and will be made only if sufficient funds are appropriated in the new biennium to satisfy the contract.

History

• Law Implemented: NDCC 54-17.5-04, 54-61-01.5

N.D. Admin. Code 43-03-05-06 Partially funded or delayed projects

If the commission grant is less than the amount requested, the applicant may decline the award or proceed with the project as proposed, notwithstanding the reduced award. Failure of a grantee to proceed with the project in a timely manner or comply with contract terms or these rules entitles the commission to cancel the grant and contract and to receive from the grantee full reimbursement of all funds the commission disbursed under the contract.

History

• History: Effective October 1, 1990; amended effective March 1, 1992.

N.D. Admin. Code 43-03-05-07 Contract modifications

If at any time after entering a contract the grantee desires to change any term of the contract, the grantee shall make a written request to the commission. The request must set forth the specific change desired and the reasons why the change is needed. Upon receipt of the request, the commission shall convey it to the council's executive committee. If the executive committee decides that the requested change is substantive, it shall refer the request to the council and the council shall review it and make a recommendation to the commission. The executive committee and council may use a technical review committee to analyze the request. If the executive committee decides that the requested change is not substantive, the executive committee shall review the request and make a recommendation to the commission. The commission, after receiving the recommendation of the council or of the executive committee, shall decide whether or not to grant the request.

N.D. Admin. Code 43-03-05-08 Reporting requirements

A grantee has the following reporting obligations:

1.Interim reports. A grantee shall submit to the commission reports summarizing the project's accomplishments and expenditures to date. The timing of the reports will be specified in the contract.

2.Special reports. If substantial progress on a project occurs earlier than anticipated, the grantee shall immediately submit to the commission a report explaining the accomplishment.

3.Final report. A comprehensive final report must be submitted to the commission by all grantees within the time specified in the contract. This report must include a single page project summary describing the purpose of the project, the work accomplished, the project's results, and the potential applications of the project. The rest of the report must explain these subjects in detail as well as the total costs of the project, a summary fiscal accounting of the entire project, any plans for developing or putting to commercial use the results of the project, and whether and in what manner the project met or failed to meet the standards referred to in subsection 7 of section 43-03-04-01.

Chapter 43-03-06 Public Information - Patent and New Technologies Policies

N.D. Admin. Code 43-03-06-02 Rights to technical data

Rights to technical data, including software developed under the terms of a grant, shall remain with the grantee.

History

• History: Effective February 1, 1988; amended effective October 1, 1990; March 1, 1992.

N.D. Admin. Code 43-03-06-03 Use for governmental purposes

The grantee may copyright and publish material developed with commission funding. The state of North Dakota and its consultants, independent contractors, and suppliers, to the extent such are providing services to the state, shall have an irrevocable royalty-free right to practice under any patents, patent applications, or other new technology developed under the commission's programs.

The intent of this section is to enable state agencies to purchase or use, or both, new technology products or processes for governmental purposes without having to pay the imputed development costs of the products or processes twice; first in the research and development state under commission funding and then later in the purchase of the processes or products. The state may not use this provision to enter into the private marketplace through direct manufacture or production of goods and services. The commission may waive the state's royalty-free right if any other governmental entity, state, federal, or foreign, provides matching funds and imposes conditions that do or may conflict with the right provided for by this section. A waiver may be given only if the following are met:

1.The grantee has requested from the other funding source a waiver of its requirements that conflict or may conflict with this section;

2.The other funding source provides at least twenty percent of the project's funding; and

3.It is unlikely the state would ever seek to use the right given the state under this section.

N.D. Admin. Code 43-03-06-04 Patent rights - Manufacturing in North Dakota

Applicants may retain the principal worldwide patent rights to any invention made with financial support under this program, except the patent holder agrees directly, or through licensing of patents, to assure that any manufacturing thereof shall substantially occur in North Dakota. Similarly, use of any new technology or other technical information derived in part from funding under this program requires that any manufacturing thereof shall substantially occur in North Dakota. For the purposes of this

section, the words "substantial" or "substantially" shall mean not that the primary manufacturing must occur in North Dakota, but rather that more than incidental manufacturing must occur in North Dakota.

The grantee or licensee or assignee, as determined by the commission, must reimburse the entire grant amount received through the commission should such licensees or assignees relocate or be established out of the state and not continue substantial manufacturing in North Dakota. The commission may choose not to enforce the "substantial manufacturing" requirement of this section if there is no person or entity in North Dakota capable of fulfilling the requirement and it is unlikely that in the near future a person or entity would be capable of satisfying the requirement.

Article 43-04 Geological Survey Paleontological Resource Protection

Chapter 43-04-01 Definitions

N.D. Admin. Code 43-04-01-01 Definitions

1."Large scale excavation permit" is a permit issued by the state geologist that allows large scale excavation or quarrying of paleontological resources (excavations that disturb a surface area of more than eighteen square feet [1.67 square meters] of material).

2."Minimum excavation and surface collecting permit" is a permit issued by the state geologist that allows the collection of paleontological resources found at the surface or removal of specimens with hand tools without extensive excavation.

3."Modified minimum excavation and surface collecting permit" is a permit issued by the state geologist to amateur collectors that allows collection only of paleontological resources that have completely weathered out of the rock or sediment.

4."Paleontological resource" must be defined as in North Dakota Century Code section 54-17.3-01.

a.Vertebrate fossils and the localities in which they are found are assumed to be paleontological resources unless they are determined not to be significant by the state geologist (bison remains would generally not be considered significant except when found in cultural context).

b.Invertebrate, plant and trace fossils and the localities in which they are found are not considered paleontological resources unless they are determined to be significant by the state geologist (sites of unusually fine preservation and type localities, the places from which the first specimens of new fossil species were described would generally be considered paleontological resources).

History

• History: Effective October 1, 1990.
• General Authority: NDCC 28-32-02
• Law Implemented: NDCC 54-17.3-03

Chapter 43-04-02 Permit Program

N.D. Admin. Code 43-04-02-01 Qualifications of applicants

Permits will be issued only to applicants who can demonstrate that they are qualified and have experience in conducting those activities. The general standards for a qualified applicant will be determined by the state geologist.

N.D. Admin. Code 43-04-02-02 Procedure of application

Anyone wishing to collect paleontological resources on lands owned by the state or any of its political subdivisions must obtain a paleontological collecting permit. Whether or not a permit is required, the state geologist shall be contacted prior to paleontological mapping or collecting of fossils other than those defined as paleontological resources on lands owned by the state or its political subdivisions. Fossils found during those activities that are believed to be paleontological resources shall be reported to the state geologist.

Commercial collecting of paleontological resources from lands owned by the state or its political subdivisions is prohibited.

1.Information required on the permit application (available from the state geologist) is determined by the state geologist and may include, but is not limited to, the following:

a.Name, mailing address, and telephone number of the applicant.

b.Information to evaluate the qualifications of the applicant including a resume.

c.Type of permit requested (modified minimum excavation and surface collecting permit, minimum excavation and surface collecting permit, or large scale excavation permit).

d.Purpose of the proposed activity.

e.Location of the proposed activity.

f.Date (start and end of the proposed activity).

g.Names and affiliations of other individuals that will be involved in the proposed activity.

2.No permit processing fee will be charged.

3.The state geologist will review and respond to the permit application within thirty days after all the application materials have been submitted.

N.D. Admin. Code 43-04-02-03 Requirements for permitholders

Requirements for permitholders are to be determined by the state geologist and must include, but not be limited to, the following:

1.Permits will be effective until December thirty-first of the year in which they are issued.

2.Permits will generally be issued for paleontological activities in geographically restricted areas.

Individuals affiliated with North Dakota institutions may obtain a statewide permit. The names of students or field assistants under supervision of these statewide permitholders must be reported to the state geologist.

3.All paleontological resources collected from state-owned lands remain the property of North Dakota.

a.Permitholders not affiliated with a North Dakota institution must return to the geological survey a representative sample of the paleontological resources collected after an appropriate period of study.

b.What constitutes a representative sample and an appropriate period of study will be determined upon proposal and request by the collector at the end of the field activity and approved by the state geologist.

c.The representative sample is to be permanently reposited in the state fossil collection or, if preferred by the collector, into the paleontological collection of one of North Dakota's universities.

d.Remaining specimens must be deposited in a suitable repository, presumably the institution where the permitholder is affiliated, where they will be available for study and public display.

e.North Dakota resident permitholders affiliated with state institutions having a paleontological collection will be expected to curate specimens into that collection but, if they so desire, can deposit the specimens with the North Dakota geological survey for curation into the state fossil collection.

4.Upon termination of field activity or expiration or revocation of the permit, the permittee shall restore the site (remove all collecting equipment, fill in excavations, and so forth).

5.The state geologist may revoke the permit at any time if it appears that the circumstances warranting revocation as stated in North Dakota Century Code section 54-17.3-04 exist.

6.The permitholder will not be released from the requirements of the permit until all the outstanding obligations of the permit have been satisfied even if the term of the permit has expired.

7.The state geologist or the state geologist's representative has the right to visit the permit area at any time and inspect all paleontological resources collected under the permit.

8.A paleontological resource site record form, supplied by the state geologist, must be filled out for each fossil site identified.

9.Six months after the termination date of the permit, a final report, containing at least the following information must be submitted to the state geologist:

a.Paleontological collecting permit number.

b.Names and affiliations of all individuals involved with the permitted activity.

c.Discussion of the purpose of the activity.

d.Description of the area where the activity took place, including the plotting of site locations on 1:24,000 United States geological survey topographic maps.

e.Methods employed during the activity.

f.Preexcavation and postexcavation photographs of the site in the case of large-scale excavation permits.

g.Discussion of the results of the activity.

h.Description of the paleontological resources collected during the activity. This includes specimen accession or catalog numbers or both.

i.All paleontological resource site record forms.

10.A copy of all publications, such as journal publications or reports, resulting from the activity conducted under the permit must be submitted to the state geologist.

11.Upon request, copies of all field notes and other data relating to the permitted activity must be made available to the state geologist.

Article 43-05 Geologic Storage of Carbon Dioxide

Chapter 43-05-01 Geologic Storage of Carbon Dioxide

N.D. Admin. Code 43-05-01-01 Definitions

The terms used throughout this chapter have the same meaning as in chapter 43-02-03 and North Dakota Century Code chapter 38-08 except:

1."Abandoned well" means a well whose use has been permanently discontinued or which is in a state of disrepair such that it cannot be used for its intended purpose or for observation purposes.

2."Activity" means any activity related to the geological storage of carbon dioxide subject to

regulation under this chapter and North Dakota Century Code chapter 38-22.

3."Aquifer" means a geologic formation, group of formations, or part of a formation that is capable of yielding a significant amount of water to a well, spring, or other point of discharge.

4."Area of review" means the region surrounding the geologic sequestration project where underground sources of drinking water may be endangered by the injection activity.

5."Bond rating" means a rating assigned to any long-term senior secured indebtedness issued by or on behalf of the storage operator, including any indebtedness issued by any governmental authority with respect to which the storage operator is obligor.

6."Carbon dioxide plume" means the extent underground, in three dimensions, of an injected carbon dioxide stream.

7."Carbon dioxide stream" means carbon dioxide that has been captured from an emission source (e.g., a coal-burning power plant), plus incidental associated substances derived from the source materials and the capture process, and any substances added to the stream to enable or improve the injection process. This does not apply to any carbon dioxide stream that meets the definition of a hazardous waste.

8."Casing" means a pipe or tubing of varying diameter and weight, which is installed into a well to maintain the structural integrity of that well.

9."Cementing" means the operation whereby a cement slurry is pumped into a drilled hole and forced behind the casing.

10."Closure period" means that period from permanent cessation of carbon dioxide injection until the commission issues a certificate of project completion.

11."Confining zone" means a geologic formation, group of formations, or part of a formation stratigraphically overlying the injection zone that acts as a barrier to fluid movement. For injection wells operating under an injection depth waiver, confining zone means a geologic formation, group of formations, or part of a formation stratigraphically overlying and underlying the injection zone.

12."Contaminant" means any physical, chemical, biological, or radiological substance or matter in water.

13."Corrective action" means the use of commission-approved methods to ensure that wells within the area of review do not serve as conduits for the movement of fluids into underground sources of drinking water.

14."Draft permit" means a document prepared under section 43-05-01-07.2 indicating the commission's tentative decision to issue a storage facility permit or modify, revoke and reissue, or terminate an existing storage facility permit.

15."Exempted aquifer" means an "aquifer" or its portion that meets the criteria in the definition of "underground sources of drinking water" but which has been exempted according to the procedures in section 43-05-01-02.4.

16."Facility area" means the areal extent of the storage reservoir.

17."Fault" means a surface or zone of rock fracture along which there has been displacement.

18."Flow lines" means pipelines transporting carbon dioxide from the carbon dioxide injection facilities to the wellhead.

19."Fluid" means any material or substance which flows or moves, whether in a semisolid, liquid, sludge, gas, or any other form or state.

20."Formation" means a body of rock characterized by a degree of lithologic homogeneity which is prevailingly, but not necessarily, tabular and is mappable on the earth's surface or traceable in the subsurface.

21."Formation fluid" means fluid present in a formation under natural conditions as opposed to introduced fluids.

22."Formation fracture pressure" means the pressure, measured in pounds per square inch, which, if applied to a subsurface formation, will cause that formation to fracture.

23."Geologic sequestration" means the geologic storage of a gaseous, liquid, or supercritical carbon dioxide stream in a storage reservoir. This term does not apply to carbon dioxide capture or transport.

24."Geologic sequestration project" means an injection well or wells used to emplace a carbon dioxide stream beneath the lowermost formation containing underground sources of drinking water; or, wells used for geologic sequestration that have been granted a waiver of the injection depth requirements; or, wells used for geologic sequestration that have received an expansion to the areal extent of an existing enhanced oil or gas recovery aquifer exemption. It includes the subsurface three-dimensional extent of the carbon dioxide plume, as well as the associated pressure front.

25."Ground water" means water occurring beneath the surface of the ground that fills available openings in rock or soil materials such that they may be considered saturated.

26."Injection well" means a nonexperimental well used to inject carbon dioxide into or withdraw carbon dioxide from a reservoir.

27."Injection zone" means a geologic formation, group of formations, or part of a formation that is of sufficient areal extent, thickness, porosity, and permeability to receive carbon dioxide through a well or wells associated with a geologic sequestration project.

28."Mechanical integrity" means the absence of significant leakage within an injection well's tubing, casing, or packer (internal mechanical integrity), or outside of the casing (external mechanical integrity).

29."Minerals" means coal, oil, and natural gas.

30."Model" means a representation or simulation of a phenomenon or process that is difficult to observe directly or that occurs over long time frames. Models that support geologic sequestration can predict the flow of carbon dioxide within the subsurface, accounting for the properties and fluid content of the subsurface formations and the effects of injection parameters.

31."Operational period" means the period during which injection occurs.

32."Packer" means a device lowered into a well, which can be expanded or compressed to produce a fluid-tight seal.

33."Person" means an individual, association, partnership, corporation, municipality, state, federal, or tribal agency, or an agency or employee thereof.

34."Plug" or "plugging" means the act or process of sealing the flow of fluid into or out of a formation through a borehole or "well" penetrating that formation.

35."Postclosure period" means that period after the commission has issued a certificate of project completion.

36."Postinjection site care" means appropriate monitoring and other actions, including corrective action, needed following cessation of injection to ensure that underground sources of drinking water are not endangered. Postinjection site care may occur in the closure or postclosure periods.

37."Pressure" means the total load or force per unit area acting on a surface.

38."Pressure front" means the zone of elevated pressure and displaced fluids created by the injection of carbon dioxide into the subsurface. The pressure front of a carbon dioxide plume refers to a zone where there is a pressure differential sufficient to cause the movement of injected fluids or formation fluids into underground sources of drinking water.

39."Project completion" means the point in time, as determined by the commission at which the certificate of project completion is issued and the storage operator is released from all regulatory requirements associated with the storage facility.

40."Stratum" (strata plural) means a single sedimentary bed or layer, regardless of thickness, that consists of generally the same kind of rock material.

41."Subsurface observation well" means a well used to observe subsurface phenomena, including the presence of carbon dioxide, pressure fluctuations, fluid levels and flow, temperature, and in situ water chemistry.

42."Surface casing" means the first string of well casing to be installed in the well.

43."Transmissive fault or fracture" means a fault or fracture that has sufficient permeability and vertical extent to allow fluids to move between formations.

44."Trapping" means the physical and geochemical processes by which injected carbon dioxide is sequestered in the subsurface. Physical trapping occurs when buoyant carbon dioxide rises in the formation until it reaches impermeable strata that inhibits further upward and lateral migration or is immoblized in pore spaces due to capillary forces. Geochemical trapping occurs when chemical reactions between the injected carbon dioxide and natural occurring minerals in the formation lead to the precipitation of solid carbonate minerals or dissolution in formation fluids.

45."Underground source of drinking water" means an aquifer or any portion of an aquifer that supplies drinking water for human consumption, or in which the ground water contains fewer than ten thousand milligrams per liter total dissolved solids and is not an exempted aquifer as determined by the commission under section 43-02-05-03.

46."Well" means a bored, drilled or driven shaft, or a dug hole, whose depth is greater than the largest surface dimension; or an improved sinkhole; or a subsurface fluid distribution system.

N.D. Admin. Code 43-05-01-02 Scope of chapter

This chapter governs the geologic storage of carbon dioxide. This chapter does not apply to applications filed with the commission proposing to use carbon dioxide for an enhanced oil or gas recovery project, rather such applications will be processed under chapter 43-02-05. 43-05-01-02.1. Application of rules for geologic storage of carbon dioxide.

In addition to the provisions in this chapter, injection wells utilized for geologic storage are subject to the provisions of chapters 43-02-03 and 43-02-05 when applicable. 43-05-01-02.2. Injection into underground source of drinking water prohibited.

Underground injection of carbon dioxide for geologic storage that causes or allows movement of fluid into an underground source of drinking water is prohibited, unless the underground source of drinking water is an exempted aquifer under section 43-02-05-03.

No storage operator shall construct, operate, maintain, convert, plug, abandon, or conduct any injection activity in a manner that allows the movement of fluid containing any contaminant into underground sources of drinking water, if the presence of that contaminant may endanger underground sources of drinking water or may adversely affect the health of persons. The applicant must show that the objectives of this section are fulfilled.

Notwithstanding any other provision of this section, the commission may take emergency action upon receipt of information that a contaminant which is present in or likely to enter a public water system or underground source of drinking water may present an imminent and substantial endangerment to the health of persons. 43-05-01-02.3. Transitioning from enhanced oil or gas recovery to geologic sequestration.

A storage operator injecting carbon dioxide for the primary purpose of geologic sequestration into an oil and gas reservoir shall apply for and obtain storage facility and injection well permits when there is an increased risk to underground sources of drinking water compared to enhanced oil or gas recovery operations. In determining if there is an increased risk to underground sources of drinking water, the commission shall consider the following factors:

1.Increase in reservoir pressure within the injection zone;

2.Increase in carbon dioxide injection rates;

3.Decrease in reservoir production rates;

4.Distance between the injection zone and underground sources of drinking water;

5.Suitability of the enhanced oil or gas recovery area of review delineation;

6.Quality of abandoned well plugs within the area of review;

7.The storage operator's plan for recovery of carbon dioxide at the cessation of injection;

8.The source and properties of injected carbon dioxide; and

9.Any additional site-specific factors as determined by the commission. 43-05-01-02.4. Exempted aquifers and expansions of areal extent of existing aquifer exemptions.

1.The commission may identify by narrative description, illustrations, maps, or other means and shall implement these rules to protect as underground sources of drinking water, all aquifers and parts of aquifers that meet the definition of "underground source of drinking water". Even if an aquifer has not been specifically identified by the commission, it is an underground source of drinking water if it meets the definition of "underground source of drinking water".

Other than United States environmental protection agency-approved aquifer exemption expansions, new aquifer exemptions shall not be issued for injection wells.

2.The commission shall identify, by narrative description, illustrations, maps, or other means, and describe in geographic and geometric terms, such as vertical and lateral limits and gradient, which are clear and definite, all aquifers or parts of aquifers that the commission proposes to designate as exempted aquifers using the criteria in section 43-02-05-03. No designation of an exempted aquifer submitted as part of the underground injection control program is final until approved by the United States environmental protection agency administrator as part of the underground injection control program.

3.A storage operator of enhanced oil or gas recovery wells may apply to the commission for approval to expand the areal extent of an aquifer exemption already in place for an enhanced oil or gas recovery well for the exclusive purpose of carbon dioxide injection for geologic sequestration. Such applications are considered a revision to the applicable federal underground injection control program or a substantial program revision to an approved state underground injection control program and are not final until approved by the United States environmental protection agency.

a.A storage operator's application must define by narrative description, illustrations, maps, or other means and describe in geographic or geometric terms, such as vertical and lateral limits and gradient that are clear and definite, all aquifers or parts thereof that are requested to be designated as exempted under section 43-02-05-03.

b.In evaluating an application, the commission shall determine that it meets the criteria for exemptions in section 43-02-05-03. In making the determination, the commission shall consider:

(1)Current and potential future use of the underground sources of drinking water to be exempted as drinking water resources;

(2)The predicted extent of the injected carbon dioxide plume, and any mobilized fluids that may result in degradation of water quality, over the lifetime of the geologic sequestration project, as informed by computational modeling performed pursuant to subdivision a of subsection 2 of section 43-05-01-05.1, in order to ensure that the proposed injection operation will not at any time endanger underground sources of drinking water, including nonexempted portions of the injection formation;

(3)Whether the areal extent of the expanded aquifer exemption is sufficient to account for any possible revisions to the computational model during reevaluation of the area of review; and (4)Information submitted to support a waiver request made by the applicant under

section 43-05-01-11.6, if appropriate. 43-05-01-02.5. Prohibition of unauthorized injection.

Any underground injection of carbon dioxide for the purpose of geologic storage, except into a well authorized by permit issued under this chapter, is prohibited. The construction of any well required to have a permit is prohibited until the permit authorizing construction of the well has been issued. 43-05-01-02.6. Existing well conversion.

Storage operators seeking to convert an existing well to an injection well for the purpose of geologic storage of carbon dioxide must demonstrate to the commission that the well is constructed in a manner that will ensure the protection of underground sources of drinking water.

N.D. Admin. Code 43-05-01-03 Books and records to be kept to substantiate reports

All owners, operators, drilling contractors, drillers, service companies, or other persons engaged in drilling, completing, operating, or servicing storage facilities shall make and keep appropriate books and records until project completion, covering their operations in North Dakota from which they may be able to make and substantiate the reports required by this chapter.

N.D. Admin. Code 43-05-01-04 Access to records

The industrial commission and the commission's authorized agents shall have access to all storage facility records wherever located. All owners, operators, drilling contractors, drillers, service companies, or other persons engaged in drilling, completing, operating, or servicing storage facilities shall permit the industrial commission, or its authorized agents, to come upon any lease, property, well, or drilling rig operated or controlled by them, complying with state safety rules and to inspect the records and operation of wells and to conduct sampling and testing. Any information so obtained shall be public information. If requested, copies of storage facility records must be filed with the commission.

History

• History: Effective April 1, 2010.

N.D. Admin. Code 43-05-01-05 Storage facility permit

1.An application for a permit must include the following:

a.A site map showing the boundaries of the storage reservoir and the location of all proposed wells, proposed cathodic protection boreholes, and surface facilities within the carbon dioxide storage facility area;

b.A technical evaluation of the proposed storage facility, including the following:

(1)The name, description, and average depth of the storage reservoirs;

(2)A geologic and hydrogeologic evaluation of the facility area, including an evaluation of all existing information on all geologic strata overlying the storage reservoir, including the immediate caprock containment characteristics and all subsurface zones to be used for monitoring. The evaluation must include any available geophysical data and assessments of any regional tectonic activity, local seismicity and regional or local fault zones, and a comprehensive description of local and regional structural or stratigraphic features. The evaluation must describe the storage reservoir's mechanisms of geologic confinement, including rock properties, regional pressure gradients, structural features, and adsorption characteristics with regard to the ability of that confinement to prevent migration of carbon dioxide beyond the proposed storage reservoir. The evaluation must also identify any productive existing or potential mineral zones occurring within the facility area and any underground sources of drinking water in the facility area and within one mile [1.61 kilometers] of its outside boundary. The evaluation must include exhibits and plan view maps showing the following:

(a)All wells, including water, oil, and natural gas exploration and development wells, and other manmade subsurface structures and activities, including coal mines, within the facility area and within one mile [1.61 kilometers] of its outside boundary;

(b)All manmade surface structures that are intended for temporary or permanent human occupancy within the facility area and within one mile [1.61 kilometers] of its outside boundary;

(c)Any regional or local faulting;

(d)An isopach map of the storage reservoirs;

(e)An isopach map of the primary and any secondary containment barrier for the storage reservoir;

(f)A structure map of the top and base of the storage reservoirs;

(g)Identification of all structural spill points or stratigraphic discontinuities controlling the isolation of stored carbon dioxide and associated fluids within the storage reservoir;

(h)Evaluation of the pressure front and the potential impact on underground sources of drinking water, if any;

(i)Structural and stratigraphic cross sections that describe the geologic conditions at the storage reservoir;

(j)The location, orientation, and properties of known or suspected faults and fractures that may transect the confining zone in the area of review, and a determination that they would not interfere with containment;

(k)Data on the depth, areal extent, thickness, mineralogy, porosity, permeability, and capillary pressure of the injection and confining zone, including facies changes based on field data, which may include geologic cores, outcrop data, seismic surveys, well logs, and names and lithologic descriptions;

(l)Geomechanical information on fractures, stress, ductility, rock strength, and in situ fluid pressures within the confining zone. The confining zone must be free of transmissive faults or fractures and of sufficient areal extent and integrity to contain the injected carbon dioxide stream;

(m)Information on the seismic history, including the presence and depth of seismic sources and a determination that the seismicity would not interfere with containment;

(n)Geologic and topographic maps and cross sections illustrating regional geology, hydrogeology, and the geologic structure of the facility area; and (o)Identify and characterize additional strata overlying the storage reservoir that will prevent vertical fluid movement, are free of transmissive faults or fractures, allow for pressure dissipation, and provide additional opportunities for monitoring, mitigation, and remediation.

(3)A review of the data of public record, conducted by a geologist or engineer, for all wells within the facility area, which penetrate the storage reservoir or primary or secondary seals overlying the reservoir, and all wells within the facility area and within one mile [1.61 kilometers], or any other distances deemed necessary by the commission, of the facility area boundary. The review must include the following:

(a)A determination that all abandoned wells have been plugged and all operating wells have been constructed in a manner that prevents the carbon dioxide or associated fluids from escaping from the storage reservoir;

(b)A description of each well's type, construction, date drilled, location, depth, record of plugging, and completion;

(c)Maps and stratigraphic cross sections indicating the general vertical and lateral limits of all underground sources of drinking water, water wells, and springs within the area of review; their positions relative to the injection zone; and the direction of water movement, where known;

(d)Maps and cross sections of the area of review;

(e)A map of the area of review showing the number or name and location of all injection wells, producing wells, abandoned wells, plugged wells or dry holes, deep stratigraphic boreholes, state-approved or United States environmental protection agency-approved subsurface cleanup sites, surface bodies of water, springs, mines (surface and subsurface), quarries, water wells, other pertinent surface features, including structures intended for human occupancy, state, county, or Indian country boundary lines, and roads;

(f)A list of contracts, submitted to the commission, when the area of review extends across state jurisdiction boundary lines;

(g)Baseline geochemical data on subsurface formations, including all underground sources of drinking water in the area of review; and (h)Any additional information the commission may require.

(4)The proposed calculated average and maximum daily injection rates, daily volume, and the total anticipated volume of the carbon dioxide stream using a method acceptable to and filed with the commission;

(5)The proposed average and maximum bottom hole injection pressure to be utilized at the reservoir. The maximum allowed injection pressure, measured in pounds per square inch gauge, shall be approved by the commission and specified in the permit. In approving a maximum injection pressure limit, the commission shall consider the results of well tests and other studies that assess the risks of tensile failure and shear failure. The commission shall approve limits that, with a reasonable degree of certainty, will avoid initiating a new fracture or propagating an existing fracture in the confining zone or cause the movement of injection or formation fluids into an underground source of drinking water;

(6)The proposed preoperational formation testing program to obtain an analysis of the chemical and physical characteristics of the injection zone and confining zone pursuant to section 43-05-01-11.2;

(7)The proposed stimulation program, a description of stimulation fluids to be used, and a determination that stimulation will not interfere with containment; and (8)The proposed procedure to outline steps necessary to conduct injection operations.

c.The extent of the pore space that will be occupied by carbon dioxide as determined by utilizing all appropriate geologic and reservoir engineering information and reservoir analysis, which must include various computational models for reservoir characterization, and the projected response of the carbon dioxide plume and storage capacity of the storage reservoir. The computational model must be based on detailed geologic data collected to characterize the injection zones, confining zones, and any additional zones;

d.An emergency and remedial response plan pursuant to section 43-05-01-13;

e.A detailed worker safety plan that addresses carbon dioxide safety training and safe working procedures at the storage facility pursuant to section 43-05-01-13;

f.A corrosion monitoring and prevention plan for all wells and surface facilities pursuant to

section 43-05-01-15;

g.A leak detection and monitoring plan for all wells and surface facilities pursuant to section

N.D. Admin. Code 43-05-01-14 The plan must:

(1)Identify the potential for release to the atmosphere;

(2)Identify potential degradation of ground water resources with particular emphasis on underground sources of drinking water; and (3)Identify potential migration of carbon dioxide into any mineral zone in the facility area;

h.A leak detection and monitoring plan to monitor any movement of the carbon dioxide outside of the storage reservoir. This may include the collection of baseline information of carbon dioxide background concentrations in ground water, surface soils, and chemical composition of in situ waters within the facility area and the storage reservoir and within one mile [1.61 kilometers] of the facility area's outside boundary. Provisions in the plan will be dictated by the site characteristics as documented by materials submitted in support of the permit application but must:

(1)Identify the potential for release to the atmosphere;

(2)Identify potential degradation of ground water resources with particular emphasis on underground sources of drinking water; and (3)Identify potential migration of carbon dioxide into any mineral zone in the facility area;

i.The proposed well casing and cementing program detailing compliance with section 43-05-01-09;

j.An area of review and corrective action plan that meets the requirements pursuant to

section 43-05-01-05.1;

k.The storage operator shall comply with the financial responsibility requirements pursuant to section 43-05-01-09.1;

l.A testing and monitoring plan pursuant to section 43-05-01-11.4;

m.A plugging plan that meets requirements pursuant to section 43-05-01-11.5;

n.A postinjection site care and facility closure plan pursuant to section 43-05-01-19; and

o.Any other information that the commission requires.

2.Any person filing a permit application or an application to amend an existing permit shall pay a processing fee. The fee will be based on actual processing costs, including computer data processing costs, incurred by the commission.

a.A record of all application processing costs incurred must be maintained by the

b.Promptly after receiving an application, the commission shall prepare and submit to the applicant an estimate of the processing fee and a payment billing schedule.

c.After the commission's work on the application has concluded, a final statement will be sent to the applicant. The full processing fee must be paid before the commission issues its final decision on an application.

d.The applicant must pay the processing fee regardless of whether a permit is issued or denied, or the application withdrawn.

3.The commission has one year from the date an application is deemed complete to issue a final decision regarding the application. 43-05-01-05.1. Area of review and corrective action.

1.The storage operator shall prepare, maintain, and comply with a plan to delineate the area of review for a proposed geologic sequestration project, periodically reevaluate the delineation, and perform corrective action that meets the requirements of this section and is acceptable to the commission. The requirement to maintain and implement a commission-approved plan is directly enforceable regardless of whether the requirement is a condition of the permit. As a

part of the storage facility permit application, the storage operator shall submit an area of review and corrective action plan that includes the following:

a.The method for delineating the area of review, including the model to be used, assumptions that will be made, and the site characterization data on which the model will be based;

b.A description of:

(1)The reevaluation date, not to exceed five years, at which time the storage operator shall reevaluate the area of review;

(2)The monitoring and operational conditions that would warrant a reevaluation of the area of review prior to the next scheduled reevaluation date;

(3)How monitoring and operational data (e.g., injection rate and pressure) will be used to inform an area of review reevaluation; and (4)How corrective action will be conducted to meet the requirements of this section, including what corrective action will be performed prior to injection and what, if any, portions of the area of review will have corrective action addressed on a phased

basis and how the phasing will be determined; how corrective action will be adjusted if there are changes in the area of review; and how site access will be guaranteed for future corrective action.

2.The storage operator shall perform the following actions to delineate the area of review and identify all wells that require corrective action:

a.Predict, using existing site characterization, monitoring and operational data, and computational modeling, the projected lateral and vertical migration of the carbon dioxide plume and its associated pressure front in the subsurface from the commencement of injection activities until the plume movement ceases, or until the end of a fixed time period as determined by the commission. The model must:

(1)Be based on detailed geologic data collected to characterize the injection zone, confining zone, and any additional zones; and anticipated operating data, including injection pressures, rates, and total volumes over the proposed life of the geologic sequestration project;

(2)Take into account any geologic heterogeneities, other discontinuities, data quality, and their possible impact on model predictions; and (3)Consider potential migration through faults, fractures, and artificial penetrations.

b.Using methods approved by the commission, identify all penetrations, including active and abandoned wells and underground mines, in the area of review that may penetrate the confining zone. Provide a description of each well's type, construction, date drilled, location, depth, record of plugging and completion, and any additional information the commission may require; and

c.Determine which abandoned wells have been plugged or operating wells have been constructed in the area of review in a manner that prevents the movement of the injected carbon dioxide or other fluids that may endanger underground sources of drinking water, including use of materials compatible with the carbon dioxide stream.

3.The storage operator shall perform corrective action on all wells in the area of review that are determined to need corrective action, using methods designed to prevent the movement of fluid into or between underground sources of drinking water, including use of materials compatible with the carbon dioxide stream, where appropriate.

4.At the reevaluation date, not to exceed five years, as specified in the area of review and corrective action plan, or when monitoring and operational conditions warrant, the storage operator shall:

a.Reevaluate the area of review in the same manner specified in subdivision a of subsection 2;

b.Identify all wells in the reevaluated area of review that require corrective action in the same manner specified in subsection 2;

c.Perform corrective action on wells requiring corrective action in the reevaluated area of review in the same manner specified in subsection 3; and

d.Submit an amended area of review and corrective action plan or demonstrate to the commission through monitoring data and modeling results that no amendment to the plan is needed. Any amendments to the plan are subject to the commission's approval, must be incorporated into the permit, and are subject to the permit modification requirements.

5.The emergency and remedial response plan and the demonstration of financial responsibility must account for the area of review, regardless of whether or not corrective action in the area of review is phased.

6.All modeling inputs and data used to support area of review delineations and reevaluations must be retained until project completion. Upon project completion, the storage operator shall deliver the records to the commission.

N.D. Admin. Code 43-05-01-06 Storage facility permit transfer

1.Notification. The storage operator and proposed transferee shall notify the commission in writing of any proposed permit transfer. The notice must contain the following:

a.The name and address of the person to whom the permit is to be transferred.

b.The name of the permit subject to transfer and location of the storage facility and a description of the land within the facility area.

c.The date that the storage operator desires the proposed transfer to occur.

d.A demonstration of financial assurance as required by section 43-05-01-09.1.

2.Transfers by modification. A storage facility permit may be transferred by the storage operator to a new storage operator only if the storage facility permit is modified, or revoked and reissued, or a minor modification made, to identify the new storage operator and incorporate such other requirements as may be necessary under state and federal laws.

3.Commission review. The commission shall review the proposed transfer to ensure that the purposes of North Dakota Century Code chapter 38-22 are not compromised but are promoted. For good cause, the commission may deny a transfer request, delay acting on it, and place conditions on its approval.

4.Commission approval required. A permit transfer can occur only upon the commission's written order. The transferor of a permit shall receive notice from the commission that the approved new storage operator has demonstrated financial responsibility for the storage facility.

N.D. Admin. Code 43-05-01-07 Amending storage facility permit

Repealed effective April 1, 2013. 43-05-01-07.1. Permitting.

1.Application for a permit under this chapter:

a.Any person who is required to have a permit shall complete, sign, and submit a permit application to the commission.

b.When the owner and storage operator are different, it is the storage operator's duty to obtain a permit.

c.The commission shall not begin processing a permit until the applicant has fully complied with the application requirements for that permit.

d.The application must be complete before the permit is issued. An application for a permit is complete when the commission receives an application form and any supplemental information which are completed to the commission's satisfaction.

2.All permit applications, reports, or information submitted to the commission must comply with the following signature and certification requirements:

a.All permit applications must be signed as follows:

(1)For a corporation by a principal executive officer of at lease the level of vice president;

(2)For a partnership or sole proprietorship by a general partner or the proprietor, respectively; or (3)For a municipality, state, federal, or other public agency by either a principal executive officer or ranking elected official.

b.All reports required by permits and other information requested by the commission must be signed by a person described in subdivision a, or by a duly authorized representative of that person. A person is a duly authorized representative only if:

(1)The authorization is made in writing by a person described in subdivision a;

(2)The authorization specifies either an individual or a position having responsibility for the overall operation of the regulated facility or activity, such as the position of plant manager, operator of a well or well field, superintendent, or position of equivalent responsibility. A duly authorized representative may thus be either a named individual or any individual occupying a named position; and (3)The written authorization is submitted to the commission.

c.If an authorization under subdivision b is no longer accurate because a different individual or position has responsibility for the overall operation of the storage facility, a new authorization pursuant to subdivision b must be submitted to the commission prior to or together with any reports, information, or applications to be signed by an authorized representative.

d.Any person signing a document under subdivision a or b shall make certification under penalty of law that that person has personally examined and is familiar with the information submitted in the document and all attachments and that, based on inquiry of those individuals immediately responsible for obtaining the information, the person believes that the information is true, accurate, and complete. Further, the person shall certify awareness that there are significant penalties for submitting false information, including the possibility of a fine and imprisonment.

3.Applicants shall provide the following information to the commission:

a.The activities conducted by the applicant which require it to obtain a storage facility permit or other federal, state, or local permits;

b.Name, mailing address, and location of the storage facility for which the application is submitted;

c.Up to four standard industrial classification codes which best reflect the principal products or services provided by the facility;

d.The storage operator's name, address, telephone number, ownership status, and status as federal, state, private, public, or other entity;

e.Whether the storage facility is located on Indian lands, historic or archaeological sites;

f.A listing of all environmental permits, construction approvals, or any other relevant permit received or applied for from the commission or any other federal, state, or local regulatory agency.

4.Applicants shall retain records of all data used to complete permit applications and supplemental information until project completion. Upon project completion, the storage operator shall deliver any records required in this section to the commission.

5.Storage operators applying to drill a new injection well shall submit an application within a reasonable time before construction is expected to begin. 43-05-01-07.2. Draft permits and fact sheets.

1.Draft permits.

a.When a storage facility permit application is complete, the commission shall either prepare a draft permit or deny the application.

b.Before preparing the draft permit, the commission shall consult the department of environmental quality.

c.The draft permit must contain the permit conditions required under sections 43-05-01-07.3 and 43-05-01-07.4.

2.Fact sheets.

a.A fact sheet must be prepared for each draft permit.

b.The fact sheet and draft permit must be sent to the applicant and, upon request, to any other person.

c.The fact sheet must include:

(1)A brief description of the type of facility or activity which is the subject of the draft permit;

(2)The quantity and quality of the carbon dioxide which is proposed to be injected and stored;

(3)A brief summary of the basis for the draft permit conditions, including references to applicable statutory or regulatory provisions;

(4)The reasons why any requested variances or alternatives to required standards do or do not appear justified;

(5)A description of the procedures for reaching a final decision on the draft permit, including:

(a)The beginning and ending dates of the comment period;

(b)The address where comments will be received;

(c)The date, time, and location of the storage facility permit hearing; and (d)Any other procedures by which the public may participate in the final decision.

(6)The name and telephone number of a person to contact for additional information. 43-05-01-07.3. Permit conditions.

The following conditions apply to all storage facility permits:

1.The storage operator shall comply with all conditions of the permit. Any noncompliance with the permit constitutes a violation and is grounds for enforcement action, including permit termination, revocation, or modification pursuant to section 43-05-01-12.

2.In an administrative action, it shall not be a defense that it would have been necessary for the storage operator to halt or reduce the permitted activity in order to maintain compliance with the conditions of the permit.

3.The storage operator shall take all reasonable steps to minimize or correct any adverse impact on the environment resulting from noncompliance with the storage facility permit.

4.The storage operator shall develop and implement an emergency and remedial response plan pursuant to section 43-05-01-13.

5.The storage operator shall at all times properly operate and maintain all storage facilities which are installed or used by the storage operator to achieve compliance with the conditions of the storage facility permit. Proper operation and maintenance includes effective performance, adequate funding, adequate operator staffing and training, and adequate laboratory and process controls, including appropriate quality assurance procedures. This provision requires the operation of backup or auxiliary facilities or similar systems only when necessary to achieve compliance with the conditions of the storage facility permit.

6.The permit may be modified, revoked and reissued, or terminated pursuant to section

N.D. Admin. Code 43-05-01-12 The filing of a request by the storage operator for a permit modification, revocation and reissuance, or termination, or a notification of planned changes or anticipated noncompliance, does not stay any permit condition

7.The injection well permit or the permit to operate an injection well does not convey any property rights of any sort or any exclusive privilege.

8.The storage operator shall furnish to the commission, within a time specified by the commission, any information which the commission may request to determine whether cause exists for modifying, revoking and reissuing, or terminating the permit, or to determine compliance with the permit. The storage operator shall also furnish to the commission, upon request, copies of records required to be kept by the storage facility permit.

9.The storage operator shall allow the commission, or an authorized representative, upon the presentation of credentials and other documents as may be required by law, to:

a.Enter upon the storage facility premises where records must be kept under the conditions of the permit;

b.At reasonable times, have access to and copy any records that must be kept under the conditions of the permit;

c.At reasonable times, inspect any facilities, equipment, including monitoring and control equipment, practices, or operations regulated or required under the permit; and

d.At reasonable times, sample or monitor for the purposes of assuring permit compliance, any substances or parameters at any location.

10.The storage operator shall prepare, maintain, and comply with a testing and monitoring plan pursuant to section 43-05-01-11.4.

11.The storage operator shall comply with the reporting requirements provided in section 43-05-01-18.

12.The storage operator must obtain an injection well permit under section 43-05-01-10 and injection wells must meet the construction and completion requirements in section 43-05-01-11.

13.The storage operator shall prepare, maintain, and comply with a plugging plan pursuant to

section 43-05-01-11.5.

14.The storage operator shall establish mechanical integrity prior to commencing injection and maintain mechanical integrity pursuant to section 43-05-01-11.1.

15.The storage operator shall implement the worker safety plan pursuant to section 43-05-01-13.

16.The storage operator shall comply with leak detection and reporting requirements pursuant to

section 43-05-01-14.

17.The storage operator shall conduct a corrosion monitoring and prevention program pursuant to section 43-05-01-15.

18.The storage operator shall prepare, maintain, and comply with the area of review and corrective action plan pursuant to section 43-05-01-05.1.

19.The storage operator shall maintain financial responsibility pursuant to section 43-05-01-09.1.

20.The storage operator shall maintain and comply with the postinjection site care and facility closure plan pursuant to section 43-05-01-19. 43-05-01-07.4. Establishing permit conditions.

1.In addition to conditions required in section 43-05-01-07.3, the commission shall establish conditions, as required on a case-by-case basis. Storage facility permits shall include conditions meeting the requirements of this chapter and such additional conditions as are necessary to prevent the endangerment of underground sources of drinking water.

2.The commission shall establish conditions in any permit as required on a case-by-case basis, to provide for and assure compliance with all statutory or regulatory requirements which take effect prior to final administrative disposition of the permit.

3.New or reissued permits, and to the extent allowed under section 43-05-01-12 modified or revoked and reissued permits, shall incorporate each of the applicable requirements referenced in this section.

4.All permit conditions shall be incorporated either expressly or by reference. If incorporated by reference, a specific citation to the applicable regulations or requirements must be given in the

N.D. Admin. Code 43-05-01-08 Storage facility permit hearing

1.The commission shall hold a public hearing before issuing a storage facility permit. At least forty-five days prior to the hearing, the applicant shall give notice of the hearing to the following:

a.Each operator of mineral extraction activities within the facility area and within one-half mile [.80 kilometer] of its outside boundary;

b.Each mineral lessee of record within the facility area and within one-half mile [.80

c.Each owner of record of the surface within the facility area and one-half mile [.80

d.Each owner of record of minerals within the facility area and within one-half mile [.80

e.Each owner and each lessee of record of the pore space within the storage reservoir and within one-half mile [.80 kilometer] of the reservoir's boundary; and

f.Any other persons as required by the commission.

2.The notice given by the applicant must contain:

a.A legal description of the land within the facility area.

b.The date, time, and place that the commission will hold a hearing on the permit application.

c.A statement that a copy of the permit application and draft permit may be obtained from the commission.

d.A statement that all comments regarding the storage facility permit application must be in writing and submitted to the commission prior to the hearing or presented at the hearing.

e.A statement that amalgamation of the storage reservoirs pore space is required to operate the storage facility, that the commission may require that the pore space owned by nonconsenting owners be included in the storage facility and subject to geologic storage, and the amalgamation of pore space will be considered at the hearing.

3.The commission shall give at least a thirty-day public notice and comment period for a draft storage facility permit, except in an emergency, including notice of the time and place of hearing thereon by one publication of such notice in a newspaper of general circulation in Bismarck, North Dakota, and in a newspaper of general circulation in the county where the land affected or some part thereof is situated, unless in some particular proceeding a longer period of time or a different method of publication is required by law, in which event such period of time and method of publication shall prevail. The notice shall issue in the name of the commission and shall conform to the other requirements provided by law. The public notice must state that an application has been filed with the commission for permission to store carbon dioxide and describe the location of the proposed facility area and the date, time, and place of the hearing before the commission at which time the merits of the application and draft permit will be considered.

4.The public notice given by the commission must contain the following:

a.Name and address of the commission;

b.Name and address of the applicant;

c.A brief description of the nature and purpose of the hearing, including the applicable rules and procedures;

d.A brief description of the activity described in the storage facility permit application or the draft storage facility permit;

e.Name, address, and telephone number of a person from whom interested persons may obtain further information, including copies of the draft storage facility permit, fact sheet, and the storage facility permit application;

f.A brief description of the comment procedures and other procedures by which the public may participate in the final permit decision;

g.The date of any previous public notices relating to the storage facility; and

h.Any additional information that the commission requires.

5.Public notice shall be given by the following methods:

a.By mailing or e-mailing a copy of the notice, the fact sheet, the storage facility permit application, and draft permit to the following:

(1)The applicant;

(2)The department of environmental quality;

(3)The state geological survey;

(4)The state water commission;

(5)The United States environmental protection agency; and (6)Federal and state agencies with jurisdiction over fish and wildlife resources, the advisory council on historic preservation, and state historical preservation officers, including any affected Indian tribes and the bureau of Indian affairs.

b.By mailing or e-mailing of copy of the public notice to the following:

(1)To any unit of local government having jurisdiction over the area where the storage facility is proposed to be located and to each state agency having any authority under state law with respect to the construction or operation of such facility.

(2)Any other person or group either upon request or on a departmental mailing list to receive geologic storage of carbon dioxide public notices:

(a)Including those who request in writing to be on the list;

(b)Persons on "area lists" from past permit proceedings in that area; and (c)Notifying the public of the opportunity to be put on the mailing list through periodic publication in the public press and in such publications as state-funded newsletters, environmental bulletins, or state law journals. The commission may update the mailing list from time to time by requesting written indication of continued interest from those listed. The commission may delete from the list the name of any person who fails to respond to such a request.

6.During the public comment period any interested person may submit written comments on the draft storage facility permit or the storage facility permit application. All comments shall be considered in making the final decision and shall be answered when a final storage facility permit is issued. The response to comments must include:

a.Provisions, if any, of the draft permit that have been changed in the final permit decision, and the reasons for the change; and

b.A brief description and response to all significant comments on the draft permit or the permit application.

7.The response to all applicable comments shall be available to the public.

N.D. Admin. Code 43-05-01-09 Well permit application requirements

1.Following receipt of a storage facility permit, the storage operator shall obtain a permit to drill, deepen, convert, operate, or, upon demonstration of mechanical integrity, reenter a previously plugged and abandoned well for storage purposes.

2.Application for permits to drill, deepen, convert, operate, or reenter a well must be submitted on form 25 provided by the commission and must include at a minimum:

a.An accurate plat certified by a registered surveyor showing the location of the proposed injection or subsurface observation well. The plat must be drawn to the scale of one inch [25.4 millimeters] equals one thousand feet [304.8 meters], unless otherwise directed by the commission, and must show distances from the proposed well to the nearest facility area boundary. The plat must show the latitude and longitude of the proposed well location to the nearest tenth of a second. The plat must also show the location and status of all other wells that have been drilled within one-fourth mile [402.34 meters], or any other distance deemed necessary by the commission, of the proposed injection or subsurface observation well;

b.The drilling, completion, or conversion procedures for the proposed injection or subsurface observation well;

c.A well bore schematic showing the name, description, and depth of the storage reservoirs and the depth of the deepest underground source of drinking water; a description of the casing in the injection or subsurface observation well, or the proposed casing program, including a full description of cement already in place or as proposed; and the proposed method of testing casing before use of the injection well;

d.A geophysical log, if available, through the storage reservoir to be penetrated by the proposed injection well or if an injection or subsurface observation well is to be drilled, a complete log through the reservoir from a nearby well is permissible. Such log must be annotated to identify the estimated location of the base of the deepest underground source of drinking water, showing the stratigraphic position and thickness of all confining strata above the reservoirs and the stratigraphic position and thickness of the reservoir;

e.The proposed pad layout, including cut and fill diagrams.

3.Within thirty days after the conclusion of well drilling and completion activities, a permit application shall be submitted to operate an injection well and must include at a minimum:

a.A schematic diagram of the surface injection system and its appurtenances;

b.A final well bore diagram showing the name, description, and depths of the storage reservoir and the base of the deepest underground source of drinking water and a diagram of the well depicting the casing, cementing, perforation, tubing, and plug and packer records associated with the construction of the well;

c.The well's complete dual induction or equivalent log through the storage reservoir. Such a log shall be run prior to setting casing through the storage reservoir. Logs must be annotated to identify the estimated location of the base of the deepest underground source of drinking water, showing the stratigraphic position and thickness of all confining strata above the storage reservoir and the reservoir's stratigraphic position and thickness unless that information has been previously submitted. When approved in advance by the commission, this information can be demonstrated with a dual induction or equivalent log run in a nearby well or by such other method acceptable to the commission;

d.An affidavit specifying the chemical constituents, their relative proportions and the physical properties of the carbon dioxide stream, and the source of the carbon dioxide stream;

e.Proof that the long string of casing of the well is cemented adequately so that the carbon dioxide is confined to the storage reservoirs. Such proof must be provided in the form of a cement bond log or the results of a fluid movement study or such other method specified by the commission;

f.The results of a mechanical-integrity test, if applicable to well type, of the casing in accordance with the pressure test requirements of this section if a test was run within one calendar year preceding the request for a conversion permit for a previously drilled well;

g.The final area of review based on modeling, using data obtained during logging and testing of the well and the formation, including any relevant updates on the geologic structure and hydrogeologic properties of the proposed storage reservoir and overlying formations;

h.Information on the compatibility of the carbon dioxide stream with fluids in the injection zone and minerals in both the injection and the confining zone, based on the results of the formation testing program, and with the materials used to construct the well;

i.The results of the formation testing program;

j.The status of corrective action on wells in the area of review;

k.All available logging and testing program data on the well;

l.Any updates to the proposed area of review and corrective action plan, testing and monitoring plan, injection well plugging plan, postinjection site care and facility closure plan, and the emergency and remedial response plan, which are necessary to address new information collected during logging and testing of the well; and

m.Any other information that the commission requires. 43-05-01-09.1. Financial responsibility.

1.The storage operator shall demonstrate and maintain financial responsibility as determined by the commission that meets the following conditions:

a.The qualifying financial responsibility instrument used must be from the following list of qualifying instruments:

(1)Trust funds;

(2)Surety or cash bonds;

(3)Letter of credit;

(4)Insurance;

(5)Self-insurance (i.e., financial test and corporate guarantee);

(6)Escrow account; or (7)Any other instrument the commission finds satisfactory.

b.The qualifying financial responsibility instrument must be sufficient to cover the cost of:

(1)Corrective action that meets the requirements of section 43-05-01-05.1;

(2)Injection well plugging that meets the requirements of section 43-05-01-11.5;

(3)Postinjection site care and facility closure that meets the requirements of section 43-05-01-19; and (4)Emergency and remedial response that meets the requirements of section 43-05-01-13.

c.The qualifying financial responsibility instrument must be sufficient to address endangerment of underground sources of drinking water.

d.The qualifying financial responsibility instrument must comprise protective conditions of coverage.

(1)Protective conditions of coverage must include at a minimum cancellation, renewal, and continuation provisions; specifications on when the provider becomes liable following a notice of cancellation if there is a failure to renew with a new qualifying financial responsibility instrument; and requirements for the provider to meet a minimum rating, minimum capitalization, and ability to pass the bond rating when applicable.

(2)Cancellation. The storage operator shall provide that its financial mechanism may not cancel, terminate, or fail to renew except for failure to pay such financial instrument. If there is a failure to pay the financial instrument, the financial institution may elect to cancel, terminate, or fail to renew the instrument by sending notice by certified mail to the storage operator and the commission. The cancellation must not be final for one hundred twenty days after receipt of cancellation notice. The storage operator shall provide an alternate qualifying financial responsibility demonstration within sixty days of notice of cancellation, and if it is not acceptable or possible, any funds from the instrument being canceled must be released to the commission within sixty days of notification by the commission.

(3)Renewal. The storage operator shall renew all qualifying financial responsibility instruments, if an instrument expires, for the entire term of the geologic sequestration project. The instrument must be automatically renewed as long as the storage operator has the option of renewal at the face amount of the expiring instrument. The automatic renewal must, at a minimum, provide the storage operator with the option of renewal at the face amount of the expiring financial instrument.

(4)Cancellation, termination, or failure to renew may not occur and the financial instrument will remain in full force and effect in the event that on or before the date of expiration:

(a)The commission deems the facility abandoned;

(b)The permit is terminated or revoked or a new permit is denied;

(c)Closure is ordered by the commission or a United States district court or other court of competent jurisdiction;

(d)The storage operator is named as debtor in a voluntary or involuntary proceeding under title 11 (bankruptcy), United States Code; or (e)The amount due is paid.

e.The qualifying financial responsibility instrument is subject to the commission's approval.

(1)The commission shall consider and approve the qualifying financial responsibility demonstration for all the phases of the geologic sequestration project prior to issuing a storage facility permit.

(2)The storage operator shall provide any updated information related to its qualifying financial responsibility instrument on an annual basis and, if there are any changes, the commission must evaluate, within a reasonable time, the qualifying financial responsibility demonstration to confirm that the instrument used remains adequate.

The storage operator shall maintain financial responsibility requirements regardless of the status of the commission's review of the financial responsibility demonstration.

(3)The commission may disapprove the use of a financial instrument if it determines that it is not sufficient to meet the requirements of this section.

f.Upon the commission's approval, the storage operator may demonstrate financial responsibility by using one or multiple qualifying financial responsibility instruments for specific phases of the geologic sequestration project.

If the storage operator combines more than one instrument for a specific geologic sequestration phase (e.g., well plugging), such combination must be limited to instruments that are not based on financial strength or performance (i.e., self-insurance or performance bond), for example trust funds, surety bonds guaranteeing payment into a trust fund, letters of credit, escrow account, and insurance. In this case, it is the combination of mechanisms, rather than the single mechanism, which must provide financial responsibility for an amount at least equal to the current cost estimate.

g.When using a third-party instrument to demonstrate financial responsibility, the storage operator shall provide proof that the third-party providers either have passed financial strength requirements based on credit ratings; or have met a minimum rating, minimum capitalization, and ability to pass the bond rating when applicable.

h.The storage operator using certain types of third-party instruments shall establish a standby trust to enable the commission to be party to the financial responsibility agreement without the commission being the beneficiary of any funds. The standby trust fund must be used along with other qualifying financial responsibility instruments (e.g., surety bonds, letters of credit, or escrow accounts) to provide a location to place funds if needed.

i.If the storage operator uses a surety bond or cash bond to satisfy its financial responsibility requirements, the storage operator shall be the principal on the bond and each surety bond must be executed by a responsible surety company authorized to transact business in North Dakota.

j.If the storage operator uses an escrow account to satisfy its financial responsibility requirements, the account must segregate funds sufficient to cover estimated costs for geologic sequestration financial responsibility from other accounts and uses.

k.If the storage operator or its guarantor uses self-insurance to satisfy its financial responsibility requirements, the storage operator shall:

(1)Meet a tangible net worth of an amount approved by the commission;

(2)Have a net working capital and tangible net worth each at least six times the sum of the current well plugging, postinjection site care, and facility closure cost;

(3)Have assets located in the United States amounting to at least ninety percent of total assets or at least six times the sum of the current well plugging, postinjection site care, and facility closure cost; and (4)Must submit a report of its bond rating and financial information annually.

l.In addition to the requirements in subdivision k, the storage operator shall either:

(1)Have a bond rating test of AAA, AA, A, or BBB as issued by Standard & Poor's, or Aaa, Aa, A, or Baa as issued by Moody's; or (2)Meet all of the following five financial ratio thresholds:

(a)A ratio of total liabilities to net worth less than 2.0;

(b)A ratio of current assets to current liabilities greater than 1.5;

(c)A ratio of the sum of net income plus depreciation, depletion, and amortization to total liabilities greater than 0.1;

(d)A ratio of current assets minus current liabilities to total assets greater than -0.1; and (e)A net profit (revenues minus expenses) greater than zero.

m.The storage operator who is not able to meet corporate financial test criteria in the preceding provision, may arrange a corporate guarantee by demonstrating that its corporate parent meets the financial test requirements on its behalf. The parent's demonstration that it meets the financial test requirement is insufficient if it has not also guaranteed to fulfill the obligations for the storage operator.

n.If the storage operator uses an insurance policy to satisfy its financial responsibility requirements, the insurance policy must be obtained from a third-party provider.

2.The requirement to maintain commission-approved qualifying financial responsibility and resources is directly enforceable regardless of whether the requirement is a condition of the

a.The storage operator shall maintain qualifying financial responsibility and resources until the commission approves project completion.

b.The storage operator may be released from a financial instrument in the following circumstances:

(1)The storage operator has completed the phase of the geologic sequestration project for which the financial instrument was required and has fulfilled all its financial obligations as determined by the commission, including obtaining financial responsibility for the next phase of the geologic sequestration project, if required;

(2)The storage operator has submitted a replacement financial instrument and received written approval from the commission accepting the new financial instrument and releasing the storage operator from the previous financial instrument; or (3)The commission approves project completion.

3.The storage operator shall have a detailed written estimate, in current dollars, of the cost of performing corrective action on wells in the area of review, plugging the injection well, postinjection site care and facility closure, and emergency and remedial response.

a.The cost estimate must be performed for each phase separately and must be based on the costs to the commission of hiring a third party to perform the required activities. A third party is a party who is not within the corporate structure of the storage operator;

b.During the active life of the geologic sequestration project, the storage operator shall adjust the cost estimate for inflation within sixty days prior to the anniversary date of the establishment of the financial instrument used to comply with this section and provide this adjustment to the commission. The storage operator shall also provide to the commission written updates of adjustments to the cost estimate within sixty days of any amendments to the area of review and corrective action plan, the injection well plugging plan, the postinjection site care and facility closure plan, and the emergency and remedial response plan;

c.Any decrease or increase to the initial cost estimate is subject to the commission's approval. During the active life of the geologic sequestration project, the storage operator shall revise the cost estimate no later than sixty days after the commission has approved the request to modify the area of review and corrective action plan, the injection well plugging plan, the postinjection site care and facility closure plan, and the emergency and remedial response plan, if the change in the plan increases the cost. If the change to the plans decreases the cost, any withdrawal of funds is subject to the commission's approval. Any decrease to the value of the financial responsibility instrument must first be approved by the commission. The revised cost estimate must be adjusted for inflation;

d.Whenever the current cost estimate increases to an amount greater than the face amount of a financial instrument currently in use, the storage operator, within sixty days after the increase, shall either cause the face amount to be increased to an amount at least equal to the current cost estimate and submit evidence of such increase to the commission, or obtain other qualifying financial responsibility instruments to cover the increase. Whenever the current cost estimate decreases, the face amount of the financial assurance instrument may be reduced to the amount of the current cost estimate only after the storage operator has received written approval from the commission.

4.The storage operator shall notify the commission by certified mail of adverse financial conditions that may affect the operator's ability to carry out its obligations under state and federal laws.

a.If the storage operator or the third-party provider of a qualifying financial responsibility instrument is named as the debtor in a bankruptcy proceeding, the notice to the commission must be made within ten days after commencement of the proceeding;

b.A guarantor of a corporate guarantee shall make the notification required in subdivision a if the guarantor is named as debtor, as required under the terms of the corporate guarantee; and

c.The storage operator who fulfills its financial responsibility requirements by obtaining a trust fund, surety bond, letter of credit, escrow account, or insurance policy will be deemed to be without the required financial assurance in the event of bankruptcy of the trustee or issuing institution, or a suspension or revocation of the authority of the trustee institution to act as trustee of the institution issuing the trust fund, surety bond, letter of credit, escrow account, or insurance policy. The storage operator shall establish other financial assurance within sixty days after such an event.

5.The storage operator shall provide an adjustment of the cost estimate to the commission within sixty days of notification by the commission, if the commission determines during the annual evaluation of the qualifying financial responsibility instrument that the most recent demonstration is no longer adequate to cover the operator's obligations under state and federal laws.

6.The use and length of pay-in periods for trust funds or escrow accounts are subject to the commission's approval. The storage operator may make periodic deposits into a trust fund or escrow account throughout the operational period in order to ensure sufficient funds are available to carry out the required activities on the date on which they may occur. The commission shall take into account project-specific risk assessments, projected timing of activities (e.g., postinjection site care), and interest accumulation in determining whether sufficient funds are available to carry out the required activities.

N.D. Admin. Code 43-05-01-10 Injection well permit

1.Upon review and approval of the application to drill, deepen, convert, reenter, or operate an injection well, submitted in accordance with section 43-05-01-09, the commission shall issue permits to drill and operate.

2.A permit shall expire twelve months from the date of issue if the permitted well has not been drilled, deepened, reentered, operated, or converted.

3.Injection well permits must be issued for the operating life of the storage facility and the closure period.

4.The commission shall review each issued injection well permit at least once every five years to determine whether it should be modified, revoked, or a minor modification made.

5.On a case-by-case basis when required by the commission, the storage operator shall submit a schedule of compliance leading to full compliance with all provisions of this chapter and North Dakota Century Code chapter 38-22.

a.Any schedules of compliance shall require compliance as soon as possible, and in no case later than three years after the effective date of the permit.

b.If the schedule of compliance is for a duration of more than one year from the date of permit issuance, then interim requirements and completion dates (not to exceed one year) must be incorporated into the compliance schedule and permit.

c.No later than thirty days following each interim and final date, the storage operator shall submit progress reports to the commission.

6.For the purposes of enforcement, compliance with an injection well permit during its term means compliance with this chapter and North Dakota Century Code chapter 38-22. However, a permit may be modified, revoked, or terminated during its term pursuant to section 43-05-01-12.

7.The issuance of an injection well permit does not convey any property rights of any sort or any exclusive privilege.

8.The issuance of an injection well permit does not authorize any injury to persons or property or invasion of other private rights or any infringement of state or local law or regulations.

9.Injection is prohibited until construction is complete, and

a.The storage operator has submitted notice of completion of construction to the commission;

b.The commission has issued an approved permit to operate an injection well; and

c.The commission has inspected or otherwise reviewed the injection well and finds it is in compliance with the conditions of the permit; or

d.The storage operator has not received notice from the commission of its intent to inspect the injection well within fourteen days of the date of the notice in subdivision a, in which case prior inspection or review is waived and the storage operator may commence permitted injection. The commission shall include in the notice a reasonable time period in which it shall inspect the well.

10.The permit shall establish any maximum injection volumes and pressures necessary to assure that fractures are not initiated in the confining zone, that injected fluids do not migrate into any underground source of drinking water, that formation fluids are not displaced into any underground source of drinking water, and to assure compliance with section 43-05-01-11.3.

N.D. Admin. Code 43-05-01-11 Injection well construction and completion standards

1.The storage operator shall ensure that all injection wells are constructed and completed to prevent movement of the carbon dioxide stream or fluids into underground sources of drinking water or outside the authorized storage reservoir. The injection wells must be constructed and completed in a way that allows the use of appropriate testing devices and workover tools. The casing and cement or other materials used in the construction of each new injection well must be designed for the well's life expectancy. In determining and specifying casing and cementing requirements, all of the following factors must be considered:

a.Depth to the injection zone;

b.Injection pressure, external pressure, internal pressure, and axial loading;

c.Hole size;

d.Size and grade of all casing strings (wall thickness, external diameter, nominal weight, length, joint specification, and construction material);

e.Corrosiveness of the carbon dioxide stream and formation fluids;

f.Down-hole temperatures;

g.Lithology of injection and confining zone;

h.Type or grade of cement and cement additives; and

i.Quantity, chemical composition, and temperature of the carbon dioxide stream.

2.Surface casing in all newly drilled carbon dioxide injection and subsurface observation wells drilled below the underground source of drinking water must be set fifty feet [15.24 meters] below the base of the lowermost underground source of drinking water and cemented pursuant to section 43-02-03-21.

3.The long string casing in all injection and subsurface observation wells must be cemented pursuant to section 43-02-03-21. Sufficient cement must be used on the long string casing to fill the annular space behind the casing to the surface of the ground and a sufficient number of centralizers shall be used to assure a good cement job. The long string casing must extend to the injection zone.

4.Any liner set in the well bore must be cemented with a sufficient volume of cement to fill the annular space.

5.All cements used in the cementing of casings in injection and subsurface observation wells must be of sufficient quality to maintain well integrity in the carbon dioxide injection environment. Circulation of cement may be accomplished by staging. The commission may approve an alternative method of cementing in cases where the cement cannot be recirculated to the surface, provided the storage operator can demonstrate by using logs that the cement does not allow fluid movement behind the well bore.

6.All casings must meet the standards specified in any of the following documents, which are hereby adopted by reference:

a.The most recent American petroleum institute bulletin on performance properties of casing, tubing, and drill pipe;

b.Specification for casing and tubing (United States customary units), American petroleum institute specification 5CT, as published by the American petroleum institute;

c.North Dakota Administrative Code section 43-02-03-21; or

d.Other equivalent casing as approved by the commission.

7.All casings used in new wells must be new casing or reconditioned casing of a quality equivalent to new casing and that has been pressure-tested in accordance with the requirements of subsection 6. For new casings, the pressure test conducted at the manufacturing mill or fabrication plant may be used to fulfill the requirements of subsection 6.

8.The location and amount of cement behind casings must be verified by an evaluation method approved by the commission. The evaluation method must be capable of evaluating cement quality radially and identifying the location of channels to ensure that underground sources of drinking water are not endangered.

9.All injection wells must be completed with and injection must be through tubing and packer. In order for the commission to determine and specify requirements for tubing and packer, the storage operator shall submit the following information:

a.Depth of setting;

b.Characteristics of the carbon dioxide stream (chemical content, corrosiveness, temperature, and density) and formation fluids;

c.Maximum proposed injection pressure;

d.Maximum proposed annular pressure;

e.Proposed injection rate (intermittent or continuous) and volume and mass of the carbon dioxide stream;

f.Size of tubing and casing; and

g.Tubing tensile, burst, and collapse strengths.

10.All tubing strings must meet the standards contained in subsection 6. All tubing must be new tubing or reconditioned tubing of a quality equivalent to new tubing and that has been pressure-tested. For new tubing, the pressure test conducted at the manufacturing mill or fabrication plant may be used to fulfill this requirement.

11.All wellhead components, including the casinghead and tubing head, valves, and fittings, must be made of steel having operating pressure ratings sufficient to exceed the maximum injection pressures computed at the wellhead and to withstand the corrosive nature of carbon dioxide.

Each flow line connected to the wellhead must be equipped with a manually operated positive shutoff valve located on or near the wellhead.

12.All packers, packer elements, or similar equipment critical to the containment of carbon dioxide must be of a quality to withstand exposure to carbon dioxide.

13.All injection wells must have at all times an accurate, operating pressure gauge or pressure recording device. Gauges must be calibrated as required by the commission and evidence of such calibration must be available to the commission upon request.

14.All newly drilled wells must establish internal and external mechanical integrity as specified by the commission and demonstrate continued mechanical integrity through periodic testing as determined by the commission. All other wells to be used as injection wells must demonstrate mechanical integrity as specified by the commission prior to use for injection and be tested on an ongoing basis as determined by the commission using these methods:

a.Pressure tests. Injection wells, equipped with tubing and packer as required, must be pressure-tested as required by the commission. A testing plan must be submitted to the commission for prior approval. At a minimum, the pressure must be applied to the tubing casing annulus at the surface for a period of thirty minutes and must have no decrease in pressure greater than ten percent of the required minimum test pressure. The packer must be set at a depth at which the packer will be opposite a cemented interval of the long string casing and must be set no more than fifty feet [15.24 meters] above the uppermost perforation or open hole for the storage reservoirs, or at the location approved by the director; and

b.The commission may require additional testing, such as a bottom hole temperature and pressure measurements, tracer survey, temperature survey, gamma ray log, neutron log, noise log, casing inspection log, or a combination of two or more of these surveys and logs, to demonstrate mechanical integrity.

15.The commission has the authority to witness all mechanical integrity tests conducted by the storage operator.

16.If an injection well fails to demonstrate mechanical integrity by an approved method, the storage operator shall immediately shut in the well, report the failure to the commission, and commence isolation and repair of the leak. The operator shall, within ninety days or as otherwise directed by the commission, perform one of the following:

a.Repair and retest the well to demonstrate mechanical integrity; or

b.Properly plug the well.

17.All injection wells must be equipped with shutoff systems designed to alert the operator and shut in wells when necessary.

18.Additional requirements may be required by the commission to address specific circumstances and types of projects.

1.An injection well has mechanical integrity if:

a.There is no significant leak in the casing, tubing, or packer; and

b.There is no significant fluid movement into an underground source of drinking water through channels adjacent to the well bore.

2.To evaluate the absence of significant leaks, the storage operator shall, following initial annulus pressure test, continuously monitor injection pressure, rate, injected volumes, pressure on the annulus between tubing and long string casing, and annulus fluid volume.

3.On a schedule determined by the commission, but at least annually, the storage operator shall use one of the following methods to determine the absence of significant fluid movement:

a.An approved tracer survey; or

b.A temperature or noise log.

4.If required by the commission, at a frequency specified in the testing and monitoring plan, the storage operator shall run a casing inspection log to determine the presence or absence of corrosion in the long string casing.

5.The commission may require alternative and additional methods to evaluate mechanical integrity. Also, the commission may allow the use of an alternative method to demonstrate mechanical integrity other than those listed above with the written approval of the United States environmental protection agency administrator. To obtain approval for a new mechanical integrity test, the commission shall submit a written request to the United States environmental protection agency administrator.

6.To conduct and evaluate mechanical integrity, the storage operator shall apply methods and standards generally accepted in the industry. When the storage operator reports the results of mechanical integrity tests to the commission, the storage operator shall include a description of the test and the method used.

7.The commission may require additional or alternative tests if the results presented by the storage operator are not satisfactory to the commission to demonstrate mechanical integrity.

8.If the commission determines that an injection well lacks mechanical integrity pursuant to this

section, the commission shall give written notice of its determination to the storage operator.

Unless the commission requires immediate cessation of injection, the storage operator shall cease injection into the well within forty-eight hours of receipt of the commission's determination. The commission may allow plugging of the well pursuant to the requirements of

section 43-05-01-11.5 or require the storage operator to perform such additional construction, operation, monitoring, reporting, and corrective action as is necessary to prevent the movement of fluid into or between underground sources of drinking water caused by the lack of mechanical integrity. The storage operator may resume injection upon written notification from the commission that the storage operator has demonstrated mechanical integrity pursuant to this section.

9.The commission may allow the storage operator of an injection well that lacks mechanical integrity pursuant to this section to continue or resume injection, if the storage operator has made a satisfactory demonstration that there is no movement of fluid into or between underground sources of drinking water. 43-05-01-11.2. Logging, sampling, and testing prior to injection well operation.

1.During the drilling and construction of an injection well, the storage operator shall run appropriate logs, surveys, and tests to determine or verify the depth, thickness, porosity, permeability, lithology, and salinity of any formation fluids in all relevant geologic formations to ensure conformance with the injection well construction requirements under section 43-05-01-11, and to establish accurate baseline data against which future measurements may be compared. The storage operator shall submit to the commission a descriptive report prepared by a log analyst that includes an interpretation of the results of such logs and tests.

At a minimum, such logs and tests must include:

a.Deviation checks during drilling on all holes constructed by drilling a pilot hole which is enlarged by reaming or another method. Such checks must be at sufficiently frequent intervals to determine the location of the borehole and to ensure that vertical avenues for fluid movement in the form of diverging holes are not created during drilling.

b.Before and upon installing the surface casing:

(1)Resistivity, spontaneous potential, and caliper logs before the casing is installed;

(2)A cement bond and variable density log to evaluate cement quality radially and a temperature log after the casing is set and cemented.

c.Before and upon installation of the long string casing:

(1)Resistivity, spontaneous potential, porosity, caliper, gamma ray, fracture finder logs, and any other logs the commission requires for the given geology before the casing is installed; and (2)A cement bond and variable density log, and a temperature log after the casing is set and cemented.

d.A series of tests designed to demonstrate the internal and external mechanical integrity of injection wells, which may include:

(1)A pressure test with liquid or gas;

(2)A tracer survey;

(3)A temperature or noise log;

(4)A casing inspection log; and

e.Any alternative methods that provide equivalent or better information and that the commission requires or approves.

2.The storage operator shall take whole cores or sidewall cores of the injection zone and confining zone and formation fluid samples from the injection zone, and shall submit to the commission a detailed report prepared by a log analyst that includes well log analyses (including well logs), core analyses, and formation fluid sample information. The commission may accept information on cores from nearby wells if the storage operator can demonstrate that core retrieval is not possible and that such cores are representative of conditions at the well. The commission may require the storage operator to core other formations in the borehole.

3.The storage operator shall record the fluid temperature, pH, conductivity, reservoir pressure, and static fluid level of the injection zone.

4.At a minimum, the storage operator shall determine or calculate the following information concerning the injection and confining zone:

a.Fracture pressure;

b.Other physical and chemical characteristics of the injection and confining zone; and

c.Physical and chemical characteristics of the formation fluids in the injection zone.

5.Upon completion, but prior to operation, the storage operator shall conduct the following tests to verify hydrogeologic characteristics of the injection zone:

a.Pressure fall-off test; and

b.Pump test; or

c.Injectivity test.

6.The storage operator shall provide the commission with the opportunity to witness all logging and testing carried out under this section. The storage operator shall submit a schedule of such activities to the commission thirty days prior to conducting the first test and submit any changes to the schedule thirty days prior to the next scheduled test. 43-05-01-11.3. Injection well operating requirements.

1.Except during stimulation, the storage operator shall ensure that injection pressure does not exceed ninety percent of the fracture pressure of the injection zone so as to ensure that the injection does not initiate new fractures or propagate existing fractures in the injection zone.

Injection pressure must never initiate fractures in the confining zone or cause the movement of injection or formation fluids that endanger an underground source of drinking water. All stimulation programs are subject to the commission's approval as part of the storage facility permit application and incorporated into the permit.

2.Injection between the outermost casing protecting underground sources of drinking water and the well bore is prohibited.

3.The storage operator shall fill the annulus between the tubing and the long string casing with a noncorrosive fluid approved by the commission. The storage operator shall maintain on the annulus a pressure that exceeds the operating injection pressure, unless the commission determines that such requirement might harm the integrity of the well or endanger underground sources of drinking water.

4.Other than during periods approved by the commission in which the sealed tubing-casing annulus is disassembled for maintenance or corrective procedures, the storage operator shall maintain mechanical integrity of the injection well at all times.

5.The storage operator shall install and use:

a.Continuous recording devices to monitor the injection pressure; the rate, volume or mass, and temperature of the carbon dioxide stream; and the pressure on the annulus between the tubing and the long string casing and annulus fluid volume; and

b.Alarms and automatic surface shutoff systems or, at the discretion of the commission, down-hole shutoff systems (e.g., automatic shutoff, check valves) or, other mechanical devices that provide equivalent protection that are designed to alert the operator and shut-in the well when operating parameters diverge beyond permitted ranges or gradients specified in the permit.

6.If a shutdown (down-hole or at the surface) is triggered or a loss of mechanical integrity is discovered, the storage operator shall immediately investigate and identify the cause as expeditiously as possible. If, upon such investigation, the well appears to be lacking mechanical integrity, or if monitoring required under subsection 5 indicates that the well may lack mechanical integrity, the storage operator shall:

a.Immediately cease injection;

b.Take all steps reasonably necessary to determine whether there may have been a release of the injected carbon dioxide stream or formation fluids into any unauthorized zone;

c.Notify the commission within twenty-four hours;

d.Restore and demonstrate mechanical integrity to the satisfaction of the commission prior to resuming injection; and

e.Notify the commission when injection can be expected to resume.

7.If any monitoring indicates the movement of injection or formation fluids into underground sources of drinking water, the commission shall prescribe such additional requirements for construction, corrective action, operation, monitoring, or reporting as are necessary to prevent such movement. These additional requirements must be imposed by modifying or terminating the permit in accordance with section 43-05-01-12 if the commission determines that cause exists, or appropriate enforcement action may be taken if the permit has been violated. 43-05-01-11.4. Testing and monitoring requirements.

The storage operator shall prepare, maintain, and comply with a testing and monitoring plan to verify that the geologic sequestration project is operating as permitted and is not endangering underground sources of drinking water. The requirement to maintain and implement a commission-approved plan is directly enforceable regardless of whether the requirement is a condition of the permit. The plan must be submitted with the storage facility permit application for commission approval and must include a description of how the storage operator will meet the requirements of this

section, including accessing sites for all necessary monitoring and testing during the life of the project.

1.The testing and monitoring plan must include:

a.Analysis of the carbon dioxide stream in compliance with applicable analytical methods and standards generally accepted by industry and with sufficient frequency to yield data representative of its chemical and physical characteristics;

b.Installation and use, except during well workovers, of continuous recording devices to monitor injection pressure, rate, and volume; the pressure on annulus between the tubing and the long string casing; and the annulus fluid volume added;

c.Corrosion monitoring of the well materials for loss of mass, thickness, cracking, pitting, and other signs of corrosion, which must be performed on a quarterly basis to ensure that the well components meet the minimum standards for material strength and performance by:

(1)Analyzing coupons of the well construction materials placed in contact with the carbon dioxide stream;

(2)Routing the carbon dioxide stream through a loop constructed with the material used in the well and inspecting the materials in the loop; or (3)Using an alternative method approved by the commission;

d.Periodic monitoring of the ground water quality and geochemical changes above the confining zone that may be a result of carbon dioxide movement through the confining zone or additional identified zones, including:

(1)The location and number of monitoring wells based on specific information about the geologic sequestration project, including injection rate and volume, geology, the presence of artificial penetrations, and other factors; and (2)The monitoring frequency and spatial distribution of monitoring wells based on baseline geochemical data and on any modeling results in the area of review evaluation;

e.A demonstration of external mechanical integrity at least once per year until the injection well is plugged; and, if required by the commission, a casing inspection log at a frequency established in the testing and monitoring plan;

f.A pressure fall-off test at least once every five years unless more frequent testing is required by the commission based on site-specific information;

g.Testing and monitoring to track the extent of the carbon dioxide plume and the presence or absence of elevated pressure (e.g., the pressure front) by using:

(1)Direct methods in the injection zone; and (2)Indirect methods (e.g., seismic, electrical, gravity, interferometric synthetic aperture radar or electromagnetic surveys and down-hole carbon dioxide detection tools), unless the commission determines, based on site-specific geology, that such methods are not appropriate;

h.The commission may require surface air monitoring and soil gas monitoring to detect movement of carbon dioxide that could endanger an underground source of drinking water. Regarding these requirements:

(1)Design of surface air and soil gas monitoring must be based on potential risks to underground sources of drinking water within the area of review;

(2)The monitoring frequency and spatial distribution of surface air monitoring and soil gas monitoring must be based on using baseline data, and the monitoring plan must describe how the proposed monitoring will yield useful information on the area of review; and (3)Surface air monitoring and soil gas monitoring methods are subject to the commission's approval;

i.Any additional monitoring, as required by the commission, necessary to support, upgrade, and improve computational modeling of the area of review evaluation;

j.Periodic reviews of the testing and monitoring plan by the storage operator to incorporate monitoring data collected, operational data collected, and the most recent area of review reevaluation performed. The storage operator shall review the testing and monitoring plan at least once every five years. Based on this review, the storage operator shall submit an amended testing and monitoring plan or demonstrate to the commission that no amendment to the testing and monitoring plan is needed. Any amendments to the testing and monitoring plan are subject to the commission's approval, must be incorporated into the permit, and are subject to the permit modification requirements.

Amended plans or demonstrations must be submitted to the commission as follows:

(1)Within one year of an area of review reevaluation;

(2)Following any significant changes to the facility, such as addition of monitoring wells or newly permitted injection wells within the area of review, on a schedule determined by the commission; or (3)When required by the commission; and

k.A quality assurance and surveillance plan for all testing and monitoring requirements.

2.Samples and measurements taken for the purpose of monitoring shall be representative of the monitored activity.

3.Records of monitoring information shall include:

a.The date, exact place, and time of sampling or measurements;

b.The individual who performed the sampling or measurements;

c.The date analyses were performed;

d.The individual who performed the analyses;

e.The analytical techniques or methods used; and

f.The results of such analyses.

4.All permits shall specify:

a.Requirements concerning the proper use, maintenance, and installation, when appropriate, of monitoring equipment or methods, including biological monitoring methods when appropriate;

b.Required monitoring, including type, intervals, and frequency sufficient to yield data, which are representative of the monitored activity, including when appropriate, continuous monitoring; and

c.Applicable reporting requirements based upon the impact of the regulated activity and as specified throughout this chapter. Reporting shall be no less frequent than specified in

section 43-05-01-18. 43-05-01-11.5. Injection well plugging.

1.Prior to the well plugging, the storage operator shall flush each injection well with a buffer fluid, determine bottom hole reservoir pressure, and perform a final external mechanical integrity test.

2.The storage operator shall prepare, maintain, and comply with a plugging plan that is acceptable to the commission. The requirement to maintain and implement a commission-approved plan is directly enforceable regardless of whether the requirement is a condition of the permit. The plan must be submitted as part of the storage facility permit application and must include the following:

a.Appropriate tests or measures for determining bottom hole reservoir pressure;

b.Appropriate testing methods to ensure external mechanical integrity;

c.The type and number of plugs to be used;

d.The placement of each plug, including the elevation of the top and bottom of each plug;

e.The type, grade, and quantity of material to be used in plugging. The material must be compatible with the carbon dioxide stream; and

f.The method of placement of the plugs.

3.The storage operator shall notify the commission in writing, at least sixty days before plugging a well, although the commission may allow a shorter period. At this time, if any changes have been made to the original well plugging plan, the storage operator shall also provide the revised well plugging plan. Any amendments to the plan are subject to the commission's approval and must be incorporated into the storage facility permit and are subject to the permit modification requirements.

4.Within sixty days after plugging, the storage operator shall submit a plugging report to the commission. The report must be certified as accurate by the storage operator and by the person who performed the plugging operation if other than the storage operator. The storage operator shall retain the well plugging report until project completion. Upon project completion the storage operator shall deliver the records to the commission. 43-05-01-11.6. Injection depth waiver requirements.

1.In seeking a waiver of the requirement to inject below the lowermost underground sources of drinking water, the storage operator shall submit a supplemental report concurrent with the storage facility permit application. The supplemental report must:

a.Demonstrate that the injection zone is laterally continuous, is not an underground source of drinking water, and is not hydraulically connected to underground sources of drinking water; does not outcrop; has adequate injectivity, volume, and sufficient porosity to safely contain the injected carbon dioxide and formation fluids; and has appropriate geochemistry;

b.Demonstrate that the injection zone is bounded by laterally continuous, impermeable confining units above and below the injection zone adequate to prevent fluid movement and pressure buildup outside of the injection zone; and that the confining unit is free of transmissive faults and fractures. The report shall further characterize the regional fracture properties and demonstrate that such fractures will not interfere with injection, serve as conduits, or endanger underground sources of drinking water;

c.Demonstrate, using computational modeling, that underground sources of drinking water above and below the injection zone will not be endangered as a result of fluid movement.

This modeling must be conducted in conjunction with the area of review determination, and is subject to requirements and periodic reevaluation;

d.Demonstrate that well design and construction, in conjunction with the waiver, will ensure isolation of the injectate in lieu of requirements and will meet well construction requirements;

e.Describe how the monitoring and testing and any additional plans will be tailored to the geologic sequestration project to ensure protection of underground sources of drinking water above and below the injection zone, if a waiver is granted;

f.Provide information on the location of all the public water supplies affected, reasonably likely to be affected, or served by underground sources of drinking water in the area of review; and

g.Provide any other information requested by the commission that the United States environmental protection agency regional administrator might find useful in making the decision whether to issue a waiver.

2.To assist the United States environmental protection agency regional administrator in making the decision whether to grant a waiver of the injection depth requirements, the commission shall submit to the regional administrator documentation of the following:

a.An evaluation of the following information as it relates to siting, construction, and operation of a geologic sequestration project with a waiver:

(1)The integrity of the upper and lower confining units;

(2)The suitability of the injection zone (e.g., lateral continuity; lack of transmissive faults and fractures; knowledge of current or planned artificial penetrations into the injection zone or formations below the injection zone);

(3)The potential capacity of the geologic formation to sequester carbon dioxide, accounting for the availability of alternative injection sites;

(4)All other site characterization data, the proposed emergency and remedial response plan, and a demonstration of financial responsibility;

(5)Community needs, demands, and supply from drinking water resources;

(6)Planned needs, potential and future use of underground sources of drinking water and nonunderground sources of drinking water in the area;

(7)Planned or permitted water, hydrocarbon, or mineral resource exploitation potential of the proposed injection formation and other formations both above and below the injection zone to determine if there are any plans to drill through the formation to access resources in or beneath the proposed injection zone;

(8)The proposed plan for securing alternative resources or treating underground sources of drinking water in the event of contamination related to the carbon dioxide injection well activity; and (9)Any other applicable considerations or information requested by the commission.

b.A review of the commission's consultation with the department of environmental quality and federally recognized Indian tribes having jurisdiction over lands within the area of review for the injection well for which a waiver is sought.

c.Any written waiver-related information submitted by the department of environmental quality to the commission.

3.The commission shall give public notice that a waiver application has been submitted. The notice must include a map of the area of review and state:

a.The depth of the proposed injection zone;

b.The location of the injection well;

c.The name and depth of all underground sources of drinking water within the area of review;

d.The names of any public water supplies affected, reasonably likely to be affected, or served by underground sources of drinking water in the area of review; and

e.The results of the consultation with the department of environmental quality.

4.Following public notice, the commission shall provide all information received through the waiver application process to the United States environmental protection agency regional administrator.

a.If the regional administrator determines that additional information is required to support a decision, the commission shall request that the applicant for the waiver provide the information.

b.The commission may not issue a waiver without written concurrence from the regional administrator.

5.Upon receipt of a waiver, the storage operator shall comply with:

a.All requirements in sections 43-05-01-5.1, 43-05-01-9.1, 43-05-01-11.1, 43-05-01-11.2, 43-05-01-11.3, 43-05-01-11.5, 43-05-01-13, and 43-05-01-18.

b.All requirements in section 43-05-01-11 with the following modifications:

(1)Injection wells must be constructed and completed to prevent movement of fluids into any unauthorized zones, including underground sources of drinking water.

(2)The casing and cementing program must be designed to prevent the movement of fluids into any unauthorized zones, including underground sources of drinking water in lieu of requirements in section 43-05-01-11.

(3)The surface casing must extend through the base of the nearest underground source of drinking water directly above the injection zone and be cemented to the surface; or, at the commission's discretion, another formation above the injection zone and below the nearest underground source of drinking water above the injection zone.

c.All requirements in section 43-05-01-11.4 with the following modifications:

(1)Ground water quality, geochemical changes, and pressure in the first underground source of drinking water immediately above and below the injection zone, and in any other formations at the discretion of the commission, must be monitored.

(2)Test and monitor to track the extent of the carbon dioxide plume and the presence or absence of elevated pressure (e.g., the pressure front) by using direct methods to monitor for pressure changes in the injection zone, and indirect methods (e.g., seismic, electrical, gravity, or electromagnetic surveys or down-hole carbon dioxide detection tools), unless the commission determines based on site-specific geology that such methods are not appropriate.

d.All requirements in section 43-05-01-19 with the following modifications for postinjection site care monitoring requirements:

(1)Ground water quality, geochemical changes and pressure in the first underground source of drinking water immediately above and below the injection zone, and in any other formations at the discretion of the commission, must be monitored.

(2)Test and monitor to track the extent of the carbon dioxide plume and the presence or absence of elevated pressure (e.g., the pressure front) by using direct methods in the injection zone, and indirect methods (e.g., seismic, electrical, gravity, or electromagnetic surveys or down-hole carbon dioxide detection tools), unless the commission determines based on site-specific geology that such methods are not appropriate.

e.Any additional requirements requested by the commission to ensure protection of underground sources of drinking water above and below the injection zone.

History

• History: Effective April 1, 2010; amended effective April 1, 2013; April 1, 2022. 43-05-01-11.1. Mechanical integrity - Injection wells.

N.D. Admin. Code 43-05-01-12 Modification, revocation, and reissuance or termination of permits

1.Permits are subject to review by the commission. Any interested person (i.e., the storage operator, local governments having jurisdiction over land within the area of review, and any person who has suffered or will suffer actual injury or economic damage) may request that the commission review permits issued under this chapter for one of the reasons set forth below.

All requests must be in writing and must contain facts or reasons supporting the request. If the commission determines that the request may have merit or at the commission's initiative for one or more of the reasons set forth below, the commission may review the permit. After review, the commission may modify or revoke a permit. Permits may be modified or revoked and reissued when the commission determines one of the following events has occurred:

a.Changes to the facility area;

b.Injecting into a reservoir not specified in the permit;

c.Any increase greater than the permitted carbon dioxide storage volume;

d.Changes in the chemical composition of the carbon dioxide stream;

e.Area of review reevaluations under subdivision a of subsection 4 of section 43-05-01-05.1;

f.Amendment to the testing and monitoring plan under subdivision j of subsection 1 of

section 43-05-01-11.4;

g.Amendment to the injection well plugging plan under subsection 3 of section 43-05-01-11.5;

h.Amendment to the postinjection site care and facility closure plan under subsection 3 of

section 43-05-01-19;

i.Amendment to the emergency and remedial response plan under subsection 4 of section 43-05-01-13;

j.Review of monitoring and testing results conducted in accordance with injection well permit requirements;

k.The commission receives information that was not available at the time of permit issuance. Permits may be modified during their terms for this cause only if the information was not available at the time of permit issuance (other than revised regulations, guidance, or test methods) and would have justified the application of different permit conditions at the time of issuance;

l.The standards or regulations on which the storage facility permit was based have been changed by promulgation of new or amended standards or regulations or by judicial decision after the permit was issued;

m.The commission determines good cause exists for modification of a compliance schedule, such as an act of God, strike, flood, or materials shortage or other events over which the storage operator has little or no control and for which there is no reasonably available remedy; or

n.There are material and substantial alterations or additions to the permitted facility or activity which occurred after permit issuance which justify the application of permit conditions that are different or absent in the existing permit.

2.If the commission tentatively decides to modify or revoke and reissue a permit, the commission shall prepare a draft permit incorporating the proposed changes. The commission may request additional information and, in the case of a modified permit, may require the submission of an updated application. In the case of a revoked and reissued permit, the commission shall require the submission of a new permit application.

3.In a permit modification under this section, only those conditions to be modified shall be reopened when a new draft permit is prepared. All other aspects of the existing permit shall remain in effect for the duration of the unmodified permit. When a permit is revoked and reissued, the entire permit is reopened just as if the permit had expired and was being reissued. During any revocation and reissuance proceeding, the storage operator shall comply with all conditions of the existing permit until a new final permit is reissued.

4.Suitability of the storage facility location will not be considered at the time of permit modification or revocation unless new information or standards indicate that a threat to human health or the environment exists which was unknown at the time of permit issuance.

5.The commission has received notification of a proposed transfer of the storage facility permit.

6.The following are causes for terminating an injection well permit during its term:

a.Noncompliance by the storage operator with any permit condition;

b.Failure by the storage operator to fully disclose all relevant facts or misrepresentation of relevant facts to the commission; or

c.A determination that the permitted activity endangers human health or the environment.

7.If the commission tentatively decides to terminate a permit, the commission shall issue notice of intent to terminate. A notice of intent to terminate is a type of draft permit which follows the same procedures as any draft permit prepared under section 43-05-01-07.2. 43-05-01-12.1. Minor modifications of permits.

Upon agreement between the storage operator and the commission, the commission may modify a permit to make the corrections or allowances without the storage operator filing an application to amend a permit. Any permit modification not processed as a minor modification under this section must be filed as an application to amend an existing permit under section 43-05-01-12. Minor modifications may include:

1.Correct typographical errors;

2.Require more frequent monitoring or reporting by the storage operator;

3.Change an interim compliance date in a schedule of compliance, provided the new date is not more than one hundred twenty days after the date specified in the existing permit and does not interfere with attaintment of the final compliance date requirement;

4.Allow for a change in ownership or operational control of a facility where the commission determines that no other change in the storage facility permit is necessary, provided that a written agreement containing a specific date for transfer of permit responsibility, coverage, and liability between the current and new storage operator has been submitted to the commission pursuant to section 43-05-01-06;

5.Change quantities or types of fluids injected which are within the capacity of the facility as permitted and, in the judgment of the commission, would not interfere with the operation of the facility or its ability to meet conditions described in the permit and would not change its classification;

6.Change construction requirements approved by the commission, provided that any such alteration shall comply with the requirements of this chapter and no such changes are physically incorporated into construction of the well prior to approval of the modification by the commission; or

7.Amend the testing and monitoring plan, plugging plan, postinjection site care and facility closure plan, emergency and remedial response plan, worker safety plan, or corrosion monitoring and prevention program where the modifications merely clarify or correct the plan, as determined by the commission.

N.D. Admin. Code 43-05-01-13 Emergency and remedial response plan

The storage operator shall implement the commission-approved emergency and remedial response plan and the worker safety plan proposed in section 43-05-01-05. This plan must include emergency response and security procedures. The plan, including revision of the list of contractors and equipment vendors, must be updated as necessary or as the commission requires. Copies of the plans must be available at the storage facility and at the storage operator's nearest operational office.

1.The emergency and remedial response plan requires a description of the actions the storage operator shall take to address movement of the injection or formation fluids that may endanger an underground source of drinking water during construction, operation, and postinjection site care periods. The requirement to maintain and implement a commission-approved plan is directly enforceable regardless of whether the requirement is a condition of the permit. The plan must also detail:

a.The safety procedures concerning the facility and residential, commercial, and public land use within one mile [1.61 kilometers], or any other distance set by the commission, of the outside boundary of the facility area; and

b.Contingency plans for addressing carbon dioxide leaks from any well, flow lines, or other facility, and loss of containment from the storage reservoir, and identify specific contractors and equipment vendors capable of providing necessary services and equipment to respond to such leaks or loss of containment.

2.If the storage operator obtains evidence that the injected carbon dioxide stream and associated pressure front may endanger an underground source of drinking water, the storage operator shall:

a.Immediately cease injection;

b.Take all steps reasonably necessary to identify and characterize any release;

c.Notify the commission within twenty-four hours; and

d.Implement the emergency and remedial response plan approved by the commission.

3.The commission may allow the operator to resume injection prior to remediation if the storage operator demonstrates that the injection operation will not endanger underground sources of drinking water.

4.The storage operator shall review annually the emergency and remedial response plan developed under subsection 1. Based on this review, the storage operator shall submit to the commission an amended plan or demonstrate to the commission that no amendment to the plan is needed. Any amendments to the plan are subject to the commission's approval, must be incorporated into the storage facility permit, and are subject to the permit modification requirements. Amended plans or demonstrations that amendments are not needed shall be submitted to the commission as follows:

a.Within one year of an area of review reevaluation;

b.Following any significant changes to the facility, such as addition of injection or monitoring wells, on a schedule determined by the commission; or

c.When required by the commission.

N.D. Admin. Code 43-05-01-14 Leak detection and reporting

1.Leak detectors or other approved leak detection methodologies must be placed at the wellhead of all injection and subsurface observation wells. Leak detectors must be integrated, where applicable, with automated warning systems and must be inspected and tested on a semiannual basis and, if defective, shall be repaired or replaced within ten days. Each repaired or replaced detector must be retested if required by the commission. An extension of time for repair or replacement of a leak detector may be granted upon a showing of good cause by the storage operator. A record of each inspection must include the inspection results, must be maintained by the operator for at least ten years, and must be made available to the commission upon request.

2.The storage operator shall immediately report to the commission any leak detected at any well or surface facility.

3.The storage operator shall immediately report to the commission any pressure changes or other monitoring data from subsurface observation wells that indicate the presence of leaks in the storage reservoir.

4.The storage operator shall immediately report to the commission any other indication that the storage facility is not containing carbon dioxide, whether the lack of containment concerns the storage reservoir, surface equipment, or any other aspect of the storage facility.

N.D. Admin. Code 43-05-01-15 Storage facility corrosion monitoring and prevention requirements

The storage operator shall conduct a corrosion monitoring and prevention program approved by the

N.D. Admin. Code 43-05-01-16 Storage facility identification requirements

Identification signs must be placed at each storage facility in a centralized location and at each well site. The signs must show the name of the operator, the facility name, and the emergency response number to contact the operator.

History

• History: Effective April 1, 2010.

N.D. Admin. Code 43-05-01-17 Storage facility fees

1.The storage operator shall pay the commission as follows:

a.Carbon dioxide sources that contribute to the energy and agriculture production economy of North Dakota:

(1)A fee of one cent on each ton of carbon dioxide injected for storage. The fee must be deposited in the carbon dioxide storage facility administrative fund.

(2)The storage operator shall pay the commission a fee of seven cents on each ton of carbon dioxide injected for storage. The fee must be deposited in the carbon dioxide storage facility trust fund.

b.Carbon dioxide sources that do not fall under the definition of subdivision a of subsection 1:

(1)The storage operator shall pay a per ton of carbon dioxide injected commission fee determined by hearing. The fee must be deposited in the carbon dioxide storage facility administrative fund and consider the commission's expenses during

regulation of the storage facility's construction, operational, and preclosure phases.

(2)The storage operator shall pay a per ton of carbon dioxide injected commission fee determined by hearing. The fee must be deposited in the carbon dioxide storage facility trust fund and must consider:

(a)The cost of postclosure emergency and remedial response associated with the storage facility.

(b)The cost of long-term monitoring postclosure associated with the storage facility.

2.Moneys from the carbon dioxide storage facility trust fund, including accumulated interest, may be relied upon to satisfy the financial assurance requirements pursuant to section 43-05-01-09.1 for the postclosure period. If sufficient moneys are not available in the carbon dioxide storage facility trust fund at the end of the closure period, the storage operator shall make additional payments into the trust fund to ensure that sufficient funds are available to carry out the required activities on the date at which they may occur. The commission shall take into account project-specific risk assessments, projected timing of activities (e.g., postinjection site care), and interest accumulation in determining whether sufficient funds are available to carry out the required activities.

History

• History: Effective April 1, 2010; amended effective April 1, 2013; April 1, 2022.

N.D. Admin. Code 43-05-01-18 Reporting requirements

1.The storage operator shall file with the commission all reports, submittals, notifications, and any other information that the commission requires.

2.The storage operator shall give notice to the commission as soon as possible of any planned physical alterations or additions to the permitted storage facility or any other planned changes in the permitted storage facility or activity which may result in noncompliance with permit requirements.

3.Reports of compliance or noncompliance with, or any progress reports on, interim and final requirements contained in any compliance schedule of this permit shall be submitted no later than thirty days following each schedule date.

4.The storage operator shall file with the commission quarterly, or more frequently if the commission requires, a report on the volume of carbon dioxide injected into or withdrawn since the last report, the average injection rate, average composition of the carbon dioxide stream, wellhead and downhole temperature and pressure data or calculations, or other pertinent operational parameters as required by the commission.

5.The storage operator shall submit all required reports, submittals, and notification under

chapter 43-05-01 to the United States environmental protection agency in an electronic format approved by that agency.

6.The quarterly report is due thirty days after the end of the quarter. The report must:

a.Describe any changes to the physical, chemical, and other relevant characteristics of the carbon dioxide stream from the proposed operating data;

b.State the monthly average, maximum, and minimum values for injection pressure, flow rate and volume, and annular pressure;

c.Describe any event that exceeds operating parameters for annulus pressure or injection pressure specified in the permit;

d.Describe any event which triggers a shutoff device required pursuant to subsection 5 of

section 43-05-01-11.3 and the response taken;

e.State the monthly volume and mass of the carbon dioxide stream injected over the reporting period and the volume injected cumulatively over the life of the project to date;

f.State the monthly annulus fluid volume added; and

g.State the results of monitoring prescribed under section 43-05-01-11.4.

7.The storage operator shall file with the commission an annual report that summarizes the quarterly reports and that provides updated projections of the response and storage capacity of the storage reservoir. The projections must be based on actual reservoir operational experience, including all new geologic data and information. All anomalies in predicted behavior as indicated in permit conditions or in the assumptions upon which the permit was issued must be explained and, if necessary, the permit conditions amended in accordance with section 43-05-01-12. The annual report is due forty-five days after the end of the year.

8.The storage operator shall report, within thirty days, the results of:

a.Periodic tests of mechanical integrity;

b.Any well workover; and

c.Any other test of the injection well conducted by the storage operator if required by the

9.The storage operator shall report the following, within twenty-four hours:

a.Any evidence that the injected carbon dioxide stream or associated pressure front may cause an endangerment to an underground source of drinking water;

b.Any noncompliance which may endanger health and safety of persons or cause pollution of the environment, including:

(1)Any monitoring or other information which indicates that any contaminant may cause an endangerment to underground sources of drinking water; or (2)Any noncompliance with a permit condition or malfunction of the injection system which may cause fluid migration into or between underground sources of drinking water shall be provided verbally within twenty-four hours from the time the storage operator becomes aware of the circumstances. A written submission shall also be provided within five days of the time the storage operator becomes aware of the circumstances. The written submission shall contain a description of the noncompliance and its cause; the period of noncompliance, including exact dates and times; and if the noncompliance has not been corrected, the anticipated time it is expected to continue; and steps taken or planned to reduce, eliminate, and prevent reoccurrence of the noncompliance.

c.Any triggering of a shutoff system (e.g., down-hole or at the surface);

d.Any failure to maintain mechanical integrity; or

e.Any release of carbon dioxide to the atmosphere or biosphere in compliance with the requirement under subdivision h of subsection 1 of section 43-05-01-11.4 for surface air and soil gas monitoring, or other monitoring technologies required by the commission.

10.The storage operator shall notify the commission in writing thirty days in advance of:

a.Any planned well workover;

b.Any planned stimulation activities, other than stimulation for formation testing conducted;

c.Any other planned test of the injection well conducted by the storage operator; and

d.The conversion or abandonment of any well used or proposed to be used in a geologic storage operation.

11.The storage operator shall retain the following records until project completion:

a.All data collected for the applications of the storage facility permit, injection well permit, and operation of injection well permit;

b.Data on the nature and composition of all injected fluids collected pursuant to subdivision a of subsection 1 of section 43-05-01-11.4; and

c.All records from the closure period, including well plugging reports, postinjection site care data, and the final assessment.

d.Upon project completion, the storage operator shall deliver any records required in this

section to the commission.

12.The storage operator shall retain the following records for a period of at least ten years from the date of the sample, measurement, or report:

a.Monitoring data collected pursuant to subdivisions b through i of subsection 1 of section 43-05-01-11.4; and

b.Calibration and maintenance records and all original strip chart recordings for continuous monitoring instrumentation, and copies of all reports required by the storage facility

c.This period may be extended by request of the commission at any time.

13.The storage operator shall report all instances of noncompliance not otherwise reported under this section, at the time monitoring reports are submitted. The reports shall contain the information listed in subsection 9.

14.Where the storage operator becomes aware that it failed to submit any relevant facts in a permit application, or submitted incorrect information in a permit application or in any report to the commission, such facts or information shall be promptly submitted to the commission.

Failure to do so may result in revocation of the permit, depending on the nature of the information withheld. 43-05-01-18.1. Abandonment of wells.

1.The removal of injection equipment or the failure to operate an injection well for one year constitutes abandonment of the well. An abandoned well must be plugged in accordance with the plugging plan and its site must be reclaimed.

2.The commission may waive for one year the requirement to plug and reclaim an abandoned well by giving the well temporarily abandoned status. This status may only be given to wells that are to be used for purposes related to the geologic storage of carbon dioxide. If a well is given temporarily abandoned status, the well's perforations must be isolated, the integrity of its casing must be proven, and its casing must be sealed at the surface, all in a manner approved by the commission. The commission may extend a well's temporarily abandoned status beyond one year. A fee of one hundred dollars shall be submitted for each application to extend the temporary abandonment status of any well.

3.In addition to the waiver in subsection 2, the commission may also waive the duty to plug and reclaim an abandoned well for any other good cause found by the commission. If the commission exercises this discretion, the commission shall set a date or circumstance upon which the waiver expires.

N.D. Admin. Code 43-05-01-19 Postinjection site care and facility closure

The storage operator shall submit and maintain the postinjection site care and facility closure plan as a part of the storage facility permit application to be approved by the commission. The requirement to maintain and implement a commission-approved plan is directly enforceable regardless of whether the requirement is a condition of the permit.

1.The postinjection site care and facility closure plan must include the following information:

a.The pressure differential between preinjection and predicted postinjection pressures in the injection zone;

b.The predicted position of the carbon dioxide plume and associated pressure front at cessation of injection as demonstrated in the area of review evaluation;

c.A description of postinjection monitoring location, methods, and proposed frequency;

d.A schedule for submitting postinjection site care monitoring results to the commission;

e.The duration of the postinjection site care monitoring time frame that ensures nonendangerment of underground sources of drinking water.

2.The storage operator shall specify in the postinjection site care and facility closure plan which wells will be plugged and which will remain unplugged to be used as subsurface observation wells. Subsurface observation and ground water monitoring wells as approved in the plan must remain in place for continued monitoring during the closure and postclosure periods.

3.Upon cessation of injection, the storage operator shall either submit an amended postinjection site care and facility closure plan or demonstrate to the commission through monitoring data and modeling results that no amendment to the plan is needed. Any amendments to the postinjection site care and facility closure plan are subject to the commission's approval and must be incorporated into the storage facility permit.

4.At any time during the life of the geologic sequestration project, the storage operator may modify and resubmit the postinjection site care and facility closure plan for the commission's approval within thirty days of such change.

5.Upon cessation of injection, all wells not associated with monitoring must be properly plugged and abandoned in a manner which will not allow movement of injection or formation fluids that endanger underground sources of drinking water in accordance with section 43-05-01-11.5. All storage facility equipment, appurtenances, and structures not associated with monitoring must be removed. Following well plugging and removal of all surface equipment, the surface must be reclaimed to the commission's specifications that will, in general, return the land as closely as practicable to original condition pursuant to North Dakota Century Code section 38-08-04.12.

6.The well casing must be cut off at a depth of five feet [1.52 meters] below the surface and a steel plate welded on top identifying the well name and that it was used for carbon dioxide.

7.The commission shall develop in conjunction with the storage operator a continuing monitoring plan for the postclosure period, including a review and final approval of wells to be plugged.

8.The storage operator shall continue to conduct monitoring during the closure period as specified in the commission-approved postinjection site care and facility closure plan. The storage operator may apply for project completion with an alternative postinjection site care monitoring time frame pursuant to North Dakota Century Code section 38-22-17. Once it is demonstrated that underground sources of drinking water are no longer endangered, the final assessment under subsection 9 is complete, and upon full compliance with North Dakota Century Code section 38-22-17, the storage operator may apply to the commission for a certificate of project completion. If the storage operator is unable to meet the requirements of North Dakota Century Code section 38-22-17 and is unable to demonstrate that underground sources of drinking water are no longer being endangered, the storage operator shall continue monitoring the storage facility for fifty years or until full compliance is met and such demonstration can be made.

9.Before project completion, the storage operator shall provide a final assessment of the stored carbon dioxide's location, characteristics, and its future movement and location within the storage reservoir. The storage operator shall submit the final assessment to the commission within ninety days of completing all postinjection site care and facility closure requirements.

a.The final assessment must include:

(1)The results of computational modeling performed pursuant to delineation of the area of review under section 43-05-01-05.1;

(2)The predicted time frame for pressure decline within the injection zone, and any other zones, such that formation fluids may not be forced into any underground sources of drinking water or the time frame for pressure decline to preinjection pressures;

(3)The predicted rate of carbon dioxide plume migration within the injection zone and the predicted time frame for the cessation of migration;

(4)A description of the site-specific processes that will result in carbon dioxide trapping, including immobilization by capillary trapping, dissolution, and mineralization at the site;

(5)The predicted rate of carbon dioxide trapping in the immobile capillary phase, dissolved phase, or mineral phase;

(6)The results of laboratory analyses, research studies, or field or site-specific studies to verify the information required in paragraphs 4 and 5;

(7)A characterization of the confining zone, including a demonstration that it is free of transmissive faults, fractures, and microfractures, and an evaluation of thickness, permeability, and integrity to impede fluid (e.g., carbon dioxide, formation fluids) movement;

(8)Any other projects in proximity to the predictive modeling of the final extent of the carbon dioxide plume and area of elevated pressures. The presence of potential conduits for fluid movement, including planned injection wells and project monitoring wells associated with the proposed geologic sequestration project;

(9)A description of the well construction and an assessment of the quality of plugs of all abandoned wells within the area of review;

(10)The distance between the injection zone and the nearest underground source of drinking water above and below the injection zone;

(11)An assessment of the operations conducted during the operational period, including the volumes injected, volumes extracted, all chemical analyses conducted, and a summary of all monitoring efforts. The report must also document the stored carbon dioxide's location and characteristics and predict how it might move during the postclosure period;

(12)An assessment of the funds in the carbon dioxide storage facility trust fund to ensure that sufficient funds are available to carry out the required activities on the date on which they may occur, taking into account project-specific risk assessments, projected timing of activities (e.g., postinjection site care), and interest accumulation in the trust fund; and (13)Any additional site-specific factors required by the commission.

b.Information submitted to support the demonstration in subdivision a must meet the following criteria:

(1)All analyses and tests for the final assessment must be accurate, reproducible, and performed in accordance with the established quality assurance standards. An approved quality assurance and quality control plan must address all aspects of the final assessment;

(2)Estimation techniques must be appropriate and test protocols certified by the United States environmental protection agency must be used where available;

(3)Predictive models must be appropriate and tailored to the site conditions, composition of the carbon dioxide stream, and injection and site conditions over the life of the geologic sequestration project;

(4)Predictive models must be calibrated using existing information when sufficient data are available;

(5)Reasonably conservative values and modeling assumptions must be used and disclosed to the commission whenever values are estimated on the basis of known, historical information instead of site-specific measurements;

(6)An analysis must be performed to identify and assess aspects of the postinjection monitoring time frame demonstration that contribute significantly to uncertainty. The storage operator shall conduct sensitivity analyses to determine the effect that significant uncertainty may contribute to the modeling demonstration; and (7)Any additional criteria required by the commission.

10.The storage operator shall provide a copy of an accurate plat certified by a registered surveyor which has been submitted to the county recorder's office designated by the commission. The plat must indicate the location of the injection well relative to permanently surveyed benchmarks. The storage operator must also submit a copy of the plat to the United States environmental protection agency regional administrator office.

11.The storage operator shall record a notation on the deed to the property on which the injection well was located, or any other document that is normally examined during title search, that will in perpetuity provide any potential purchaser of the property the following information:

a.The fact that land has been used to sequester carbon dioxide;

b.The name of the state agency, local authority, or tribe with which the survey plat was filed, as well as the address of the United States environmental protection agency regional office to which it was submitted; and

c.The volume of fluid injected, the injection zone or zones into which it was injected, and the period over which injection occurred.

History

• History: Effective April 1, 2010; amended effective April 1, 2013; April 1, 2018.

N.D. Admin. Code 43-05-01-20 Determining storage amounts

1.Upon application by an enhanced oil or gas recovery unit operator or a storage operator, the commission, after notice and hearing, shall issue an order determining the amount of injected carbon dioxide stored in a reservoir that has been or is being used for an enhanced oil or gas recovery project or in a storage reservoir that has been or is being used for storage under a permit issued pursuant to North Dakota Century Code chapter 38-22.

2.The applicant shall pay a processing fee for a storage amount determination.

The applicant shall pay a processing fee based on the commission's actual processing costs, including computer data processing costs, as determined by the commission. The following procedures and criteria will be utilized in establishing the fee:

a.A record of all application processing costs incurred must be maintained by the

b.Promptly after receiving an application, the commission shall prepare and submit to the applicant an estimate of the processing fee.

c.After the commission's work on the application has concluded, a final statement will be sent to the applicant. The full processing fee must be paid before the commission issues its decision on the application.

d.The applicant must pay the processing fee even if the application is denied or withdrawn.