15 CAR pt. 275 | 15 CAR Part 275 — General Rules

Chapter XV

Subchapter A

Subpart 1

15 CAR § 275-101 General hearing procedures {#sec-15-car-275-101 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-101}

15 CAR § 275-101. General hearing procedures.

(a) Execution and filing.

(1)(A) All applications, except for applications filed by the Director of Production and Conservation, shall:

(i) Be in writing; and

(ii) State the:

(a) Interests of the application; and

(b) General nature of the order requested.

(B) Fourteen (14) copies of the application, including exhibits, shall be filed with the director’s office located in North Little Rock, Arkansas.

(2)(A) All fourteen (14) copies of the applications, including exhibits, except for those filed by the director, must be received in the director’s office at least twenty (20) days prior to the first day of regularly scheduled hearing.

(B) If the applicant or his or her representative files an electronic version (a PDF file labeled by the assigned docket number) of the application, including exhibits, on an electronic storage device approved by the director a minimum of twenty (20) days prior to the first day of the regularly scheduled hearing, the fourteen (14) copies of the applications, including exhibits, must be received in the director’s office eighteen (18) days prior to the first day of the regularly scheduled hearing.

(3)(A) Every application shall be signed by the applicant or his or her representative and his or her address shall be stated thereon.

(B) The signature of the applicant or his or her representative constitutes a certificate by him or her that:

(i) He or she has read the petition; and

(ii) To the best of his or her knowledge, information, and belief, there is good ground to support the same.

(4) Unless otherwise provided by general rule of the Oil and Gas Commission, each application, except for applications filed by the director, shall be accompanied by a five-hundred-dollar filing fee made payable to the Oil and Gas Commission.

(5)(A) The applicant shall also submit a check payable to the Oil and Gas Commission in an amount approved by the commission, not to exceed two dollars ($2.00) per name of persons named in the application whose addresses are known, as well as addresses for other persons that the applicant seeks to provide a copy of the order.

(B) The applicant shall also provide mailing labels for each person named in the application whose address is known, as well as any other person that the applicant seeks to provide a copy of the order.

(D) All mailing labels shall be provided within three (3) days after the date of the hearing.

(6) If after the application is filed, and prior to the hearing date, the director finds the application deficient relative to the requirements of subdivisions (a)(1) – (4) of this section, the director shall return the application to the applicant with a statement as to the deficiencies.

(7) If, after the application is filed, and prior to the hearing date, the director determines that additional facts, data, records, or other information are necessary to fully evaluate the application, the director may require the applicant to submit such necessary:

(A) Facts;

(B) Data;

(D) Other information.

(8)(A) Amendments may be filed at the time of the hearing.

(B) However, any amendments filed prior to the hearing date shall:

(i) Be submitted at least ten (10) days prior to the hearing date; and

(ii) Contain a written statement or a clear indication as to what amendment is being amended.

(C) Any application that is substantially amended, as determined by the commission, regardless of the time of the amendment, may be continued until the next hearing of the commission.

(b) Notice of hearing.

(1)(A) The applicant shall prepare a notice of hearing which shall be issued in the name of the commission.

(B) Such notice shall include a statement pertaining to:

(i) The legal authority for the hearing;

(ii) The name of the applicant;

(iii) The legal description of the property or unit;

(iv) The requested action;

(v) A listing of interested parties;

(vi) The time, date, and location of the hearing;

(vii) The commission assigned docket number; and

(viii) The contact information of the commission offices.

(i) Any interested person may file an entry of appearance in the hearing by submitting such entry of appearance in writing to the hearing officer or director; and

(ii) Thereafter such person shall be deemed a party of record in the proceeding.

(2) Unless otherwise provided by the Brine Act found in Arkansas Code § 15-76-201 et seq., or general rule of the commission, the applicant shall serve such notice in the following manner:

(A) By mailing such notice by United States Postal Service, first-class mail, directed to all interested parties at their last known addresses at least ten (10) days prior to the date of the hearing, but not more than thirty (30) days prior to the date of the hearing; and

(B) By publication of such notice for at least one (1) day, with the notice appearing at least ten (10) days prior to the date of the hearing, but not more than thirty (30) days prior to the date of the hearing, in the newspaper of general circulation published in each county containing some portion of the land identified in the application.

(1) In the event an emergency is found to exist by the commission which in its judgment requires the making, changing, renewal, or extension of an order or special rule, without first having a hearing, such emergency order shall have the same validity as if a hearing with respect to the same had been held after due notice.

(2) The emergency order permitted by this section shall remain in force until the date of the next regular commission hearing set to be held after the emergency rule or order was issued, or sixty (60) days from its effective date in accordance with the Brine Act found in Arkansas Code § 15-76-307, and, in any event, it shall expire when any order made after due notice and hearing with respect to the subject matter of such emergency order becomes effective.

(d) Prehearing conferences.

(1) Upon his or her own motion, or the motion of a party of record, the hearing officer, as designated by the commission, may convene a meeting of the parties or their counsel in order to:

(A) Simplify the factual and legal issues presented by the hearing request;

(B) Receive stipulations, admissions of fact, and the contents and authenticity of documents;

(C) Exchange lists of witnesses the parties intend to have testify and copies of all documents the parties intend to introduce into evidence at the hearing; and

(D) Discuss and resolve such other matters as may tend to expedite the disposition of the hearing request and to assure a just conclusion thereof.

(2) Prehearing conferences may be held by telephone conference if such procedure is acceptable to all parties.

(e) Hearings.

(1)(A) Every hearing shall be held on a date and at a location established by the commission, and conducted by a hearing officer designated by the commission.

(B) The hearing officer shall:

(i) Take all necessary actions to:

(a) Avoid delay;

(b) Maintain order; and

(ii) Have all powers necessary and appropriate to conduct a fair hearing and to render a decision on the petition, including but not limited to, the following:

(a) To administer oaths and affirmations;

(b) To receive relevant evidence;

(d) To consider and rule upon procedural requests;

(e) To examine witnesses and direct witnesses to testify, limit the number of times any witness may testify, limit repetitive or cumulative testimony, and set reasonable limits on the amount of time each witness may testify; and

(f)(1) To require the production of documents or subpoena the appearance of witnesses, either on the hearing officer’s own motion or for good cause shown on motion of any party of record.

(2) The hearing officer may require that relevant documents be produced to any party of record on his or her own motion or for good cause shown on motion of any party of record.

(2)(A) Every person appearing shall enter his or her appearance by stating his or her name and address.

(B) Thereafter, such person shall be deemed a party of record.

(3)(A) All participants in the hearing shall have the right to be represented by an attorney licensed to practice law in the State of Arkansas.

(B) An attorney appearing in a representative capacity in any proceeding hereunder shall file a written notice of appearance identifying:

(i) His or her name, address, and telephone number; and

(ii) The party represented.

(4) The hearing officer shall allow all parties to present statements, testimony, evidence, and argument as may be relevant to the proceeding.

(5) The director, or his or her designee, may appear at any public hearing and shall have the opportunity to question parties or otherwise elicit such information as is necessary to reach a decision on the application.

(6) Preliminary matters. Where applicable, the following shall be addressed prior to receiving evidence:

(A) The applicant may offer preliminary exhibits, including:

(i) Documents necessary to present the issues to be heard;

(ii) Notices;

(iii) Proof of publication; and

(iv) Orders previously entered in the cause;

(B) Rulings may be made by the hearing officer on any pending motions; and

(7) Every hearing shall be conducted in accordance with the commission’s rules and applicable laws of this state.

(f) Evidence.

(1) Admissibility.

(A) A party shall be entitled to present his or her case by oral or documentary evidence, to submit rebuttal evidence, and to conduct such cross-examination as may be required for a full and true disclosure of the facts.

(B) Any oral or documentary evidence may be received, but the presiding hearing officer may exclude evidence which is:

(i) Irrelevant;

(ii) Immaterial;

(iii) Unduly prejudicial; or

(iv) Repetitious.

(2) Official notice.

(A) Official notice may be taken of any material fact not appearing in evidence in the record if the circuit courts of this state could take judicial notice of such fact.

(B) In addition, notice may be taken of generally recognized technical or scientific facts within the commission’s specialized knowledge.

(3) Order of proof.

(A) The applicant shall open the proof.

(B) Other parties of record shall be heard immediately following the petitioner.

(D) In all cases, the hearing officer:

(i) Shall designate the order of proof; and

(ii) May limit the scope of examination or cross-examination.

(4) Briefs. The hearing officer may require or allow parties to submit written briefs to the hearing officer within:

(A) Ten (10) days after the close of the hearing; or

(B) Such other time as the hearing officer shall determine as being consistent with the commission’s responsibility for an expeditious decision.

(g) Recording of proceedings — Testimony.

(1) The commission shall provide a certified court reporter to take down the testimony and preserve a record of all proceedings at the hearing.

(2)(A) Any person testifying shall be required to do so under oath.

(B) However, relevant unsworn statements, comments, and observations by any interested person may be heard and considered by the commission as such and included in the record.

(h) Postponement or continuance of hearing.

(1) Any hearing may be postponed or continued for due cause:

(A) By the hearing officer upon his or her own motion; or

(B) Upon the motion of a party to the hearing.

(2) A motion filed by a party to the hearing shall set forth facts attesting that the request for continuance is not solely for the purpose of delay.

(3) All parties involved in a hearing shall avoid undue delay caused by repetitive postponements or continuances so that the subject matter of the hearing may be resolved expeditiously.

(4)(A) The applicant may postpone or continue the hearing of an application for three (3) consecutive regularly scheduled commission meetings without prior approval of the hearing officer.

(B) After the third consecutive postponement, the application shall be dismissed, unless the hearing officer allows an exception for due cause, and the applicant shall be required to refile in accordance with applicable general rules in order for an application to be scheduled for a hearing.

(i) Default — Failure to appear.

(1) If a party, after proper service of notice, fails to appear at the prehearing conference or at a hearing, and if no continuance is granted, the commission may then proceed to make its decision in the absence of such party.

(2)(A) If the failure to appear at such prehearing conference or hearing is due to an emergency situation beyond the parties' control, and the commission is notified of such situation on or before the scheduled prehearing conference or hearing, the hearing officer may continue or postpone the prehearing conference or hearing.

(B) Emergency situations include:

(i) Sudden unavailability of counsel;

(ii) Sudden illness of a party or his or her representative; or

(iii) Similar situations beyond the parties' control.

(j) Administrative issuance of default integration order for certain unleased mineral interests.

(1) The director is authorized to issue an administrative order integrating unleased mineral interest owners in any unit where there is not a well capable of production if all of the following criteria are met:

(A) An application is filed with the director that includes all of the information required in 15 CAR §§ 275-102(b)(2)(A)(i) – (vii);

(B) Each mineral interest sought to be integrated is less than one (1) net mineral acre;

(C) The cash bonus and royalty rate requested by the applicant are equal to or greater than the highest and/or best cash bonus and royalty terms that the applicant has knowledge of that have been offered and accepted, or contracted for, for any acreage within the unit or units where the well is located, as defined in 15 CAR § 275-203(a)(2), including any acreage within the unit or units subject to leases or other agreements with a fee mineral owner covering lands located in more than one (1) unit;

(D) The applicant specifies which Model Form Operating Agreement approved by the commission it seeks to use, with Paragraph III.1.A.(1) of the COPAS:

(i) Not to exceed more than seven thousand five hundred dollars ($7,500) for a drilling well rate and seven hundred fifty dollars ($750) for a producing well when the proposed well is a dry natural gas well; or

(ii) Not to exceed more than four thousand five hundred dollars ($4,500) for a drilling well rate and four hundred fifty dollars ($450) for a producing well when the proposed well is a liquid hydrocarbon well;

(E) The applicant provides an affidavit or other documentary evidence to support a reasonable risk factor penalty, and the requested risk factor does not exceed four hundred percent (400%);

(F) No earlier than ten (10) business days prior to, and no later than three (3) business days prior to, the filing of the application, the applicant shall send to affected mineral interests owners, whose mailing addresses may reasonably be ascertained, a notice of the application’s filing and verify such mailing by affidavit, setting out the names and addresses of all owners and the date or dates of mailing;

(G) The applicant shall also submit proof of publication of such notice of the applications in a newspaper of general circulation within the county or counties within which the unit is located that appeared at least one (1) time no earlier than ten (10) days prior to filing the application, and no later than the date of filing the application;

(H)(i) Any owner, so noticed, shall have the right to object to the granting of such application within fifteen (15) days after the date of receipt of the application by the commission.

(ii) Each objection must be made in writing and filed with the director.

(iii) If a timely written objection is filed, then the applicant shall be promptly furnished a copy and such application shall be denied, unless the objection is withdrawn within the original fifteen-day time period after receipt of the application.

(iv) If the application is denied under this section, the applicant may request to have the application referred to the commission for determination in accordance with this section and 15 CAR § 275-102, and other applicable hearing requirements, except that no additional fee is required; and

(I) If no timely objection is received, or if one is received and withdrawn within the original fifteen-day time period after receipt of the application, the director is authorized to approve the application administratively.

(2)(A) An application may be referred to the commission for determination when the director deems it necessary that the commission make such determination for the purpose of protecting correlative rights of all parties, in order to prevent waste, or for any other reason.

(C) If the application is referred under this section, the applicant shall file a request for a hearing, in accordance with this section and 15 CAR § 275-102, and other applicable hearing requirements, except that no additional filing fee is required.

(3) If the applicant has satisfied all applicable provisions, the director has not notified the applicant of the determination to refer the application to the commission within the fifteen-day period in accordance with the foregoing provisions, and if no objection is received at the office of the commission within the fifteen (15) days as provided for in subdivision (j)(1)(H) of this section, the application shall be approved and an administrative default order shall be issued by the director.

(k) Voting.

(1) In order for the commission to adopt a motion approving an application as applied for, or as amended by either the applicant or a commissioner, there must be:

(A) A quorum present;

(B) A majority of the votes cast must be in favor of the motion outlining the proposed order; and

(2) If a motion approving the application as applied for, or as modified by either the applicant or a commissioner, does not receive the votes required in subdivision (k)(1) of this section, and no subsequent or substitute motion receives the votes required in subdivision (k)(1) of this section, then the application shall be deemed to be denied by the commission.

(3) If an application is deemed to be denied by the commission in accordance with subsection (k)(2) of this section, the commission shall enter an order of denial, which may be appealed as a final decision under the Arkansas Administrative Procedure Act found in Arkansas Code § 25-15-201 et seq.

(4) Nothing in this subsection (k) shall limit the commission’s authority to continue any application for due cause.

(l) Commission’s order — Final administrative decision.

(1) Within thirty (30) days of the close of the hearing record, the commission shall issue:

(A) Findings of fact;

(B) Conclusions of law; and

(2) The commission shall have continuing jurisdiction for the purposes of enforcement, and/or modifications or amendments to the provisions of all orders.

(3) Any appeals shall be governed by the Arkansas Administrative Procedure Act found in Arkansas Code § 25-15-201 et seq.

(m) Notice of order — Recordation. Within thirty (30) days after an order has been issued, a copy of such order shall be:

(1) Mailed by the commission to each interested party at his or her last known address or his or her attorney of record; and

(2) Filed in accordance with the Arkansas Administrative Procedure Act found in Arkansas Code § 25-15-201 et seq.

(n) Official record. In every case of adjudication, the official record shall be complied in accordance with the Arkansas Administrative Procedure Act found in Arkansas Code § 25-15-201 et seq.

History

Codification Notes: “COPAS” means the Council of Petroleum Accountants Societies.This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book; amended April 13, 2008; amended June 5, 2009; amended October 24, 2009; amended July 1, 2016)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-102 Additional requirements for specific types of hearings {#sec-15-car-275-102 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-102}

15 CAR § 275-102. Additional requirements for specific types of hearings.

(a) Abandoned well and emergency response hearings.

(1) Unless otherwise specified below, 15 CAR § 275-101 shall apply to all abandoned well and emergency response hearing proceedings pursuant to Arkansas Code § 15-72-217.

(2) The Director of Production and Conservation shall only provide notice to the permit holder named in the application, in accordance with 15 CAR § 275-101(b)(2).

(3)(A) The director shall have the burden of proof at the hearing.

(B) A decision shall be supported by a substantial evidence standard.

(b) Integration hearings.

(1) Unless otherwise specified below, 15 CAR § 275-101 shall apply to all drilling unit integration proceedings heard by the Oil and Gas Commission.

(2) Commencement of action.

(A) Where the oil or gas rights within a drilling unit are separately owned and the owners of those rights have not voluntarily agreed to integrate or pool those rights to develop the oil or gas, an owner may petition the commission for an order integrating those rights, pursuant to Arkansas Code §§ 15-72-302 and 15-72-303.

(B) The application for an order integrating interests shall contain the following:

(i) The name and address of the applicant;

(ii) The applicant’s reasons for desiring to integrate the separately owned interests;

(iii) A legal land description of the drilling unit sought to be established;

(iv) A geologic report of the area where the proposed drilling unit is to be located indicating the potential presence of reservoirs;

(v) If the application is for the integration of an exploratory drilling unit, as contemplated by Arkansas Code § 15-72-302:

(a) The names of all owners named in the application who have not agreed to integrate their interests in the right to drill and produce oil or gas, or both, in the proposed drilling unit as of the date of filing the petition, as disclosed by the records in the office of the clerk for the county or counties in which the drilling unit is situated; and

(b) A statement that the persons who own at least an undivided fifty percent (50%) interest in the right to drill and produce oil or gas, or both, from the total proposed unit agree thereto at the time of the filing of the application;

(vi) If the application is for the integration of an established drilling unit, as contemplated by Arkansas Code § 15-72-303, and created in accordance with applicable commission orders or general rules, the names of all owners named in the application who have not agreed to integrate their interests in the right to drill and produce oil or gas, or both, in the proposed drilling unit as of the date of filing the petition, as disclosed by the records in the office of the clerk for the county or counties in which the drilling unit is situated;

(vii) Unleased mineral owners.

(a)(1) A resume of efforts showing that the applicant has exercised due diligence to locate each unleased mineral owner, and that a bona fide effort was made to reach an agreement with each owner as to how the unit would be developed, as follows.

(2)(A) “Due diligence” regarding nonindustry owners (persons who are not actively involved in the oil and gas business) means, except for good cause shown, to be determined at the discretion of the commission, that the applicant attempted to contact said owners and that bona fide efforts to reach an agreement commenced at least sixty (60) days prior to the date of the hearing, and that there are sufficient contacts to show that the applicant has exhausted all reasonable efforts to reach an agreement.

(B) However, the applicant shall not be required to contact an owner that the applicant is precluded by law from contacting, or an owner who has expressly stated that the applicant is not to contact said owner.

(3) “Due diligence” regarding industry owners (persons who as an active business practice are involved in the oil and gas business) means that the applicant has provided industry owners notice, including an Authorization for Expenditure (AFE) and well proposal prior to filing the integration application.

(b)(1) An affidavit indicating what the highest and/or best cash bonus and royalty terms that the applicant has knowledge of that have been offered and accepted, or contracted for, for any acreage within the unit where the well is located as defined in 15 CAR § 275-203(a)(2), including any acreage within the unit subject to leases or other agreements with a fee mineral owner covering lands located in more than one (1) unit.

(2) If this information changes prior to the hearing, the applicant shall inform the commission of any changes.

(3) If no affidavit is provided prior to or at the time of the hearing, the applicant shall provide sworn testimony as to the highest and/or best cash bonus and royalty terms that the applicant has knowledge of that have been offered and accepted, or contracted for, for any acreage within the unit where the well is located, as defined in 15 CAR § 275-203(a)(2), including any acreage within the unit subject to leases or other agreements with a fee mineral owner covering lands located in more than one (1) unit;

(viii) Uncommitted leasehold working interest owners. A resume of efforts showing that the applicant has exercised due diligence to locate each uncommitted leasehold working interest owner and that a bona fide effort was made to reach an agreement with each owner as to how the unit would be developed by providing the uncommitted leasehold working interest owners notice, including an AFE and well proposal, prior to filing the integration application; and

(ix) Any other information relevant to protect correlative rights of the parties sought to be affected by the order.

(1) Any interested party may appeal a permit denial, any enforcement action, or rule interpretation decision made by the director to the commission.

(2) Unless otherwise specified below, 15 CAR § 275-101 shall apply to all hearings requested to appeal a decision of the director.

(3) The application to appeal a director’s decision shall be accompanied by a two-hundred-fifty-dollar filing fee.

(d) Exceptional well location.

(1) Unless otherwise specified below, 15 CAR § 275-101 shall apply to all hearings for an application which has been referred to the commission in accordance with 15 CAR § 275-227, or for which 15 CAR § 275-227 is not applicable.

(2) The application shall include proof of notice to each owner within the unit in which the well is located and within the units offsetting the boundary line or lines, or in the case of wells in uncontrolled fields within the boundaries of mineral lease lines and the offsetting lease or leases which shall be encroached upon by the exceptional well location.

(3) If the application has been referred to the commission in accordance with 15 CAR § 275-227, no application fee is required to be submitted with the application.

(e) Authority to commingle and additional completions.

(1) Unless otherwise specified below, 15 CAR § 275-101 shall apply to all hearings for which the applicant has requested a hearing for an application which has been denied in accordance with 15 CAR § 275-407 or 15 CAR § 275-408, or for which 15 CAR § 275-407 or 15 CAR § 275-408 are not applicable.

(2) If the applicant requests the hearing in accordance with 15 CAR § 275-407, the application shall include proof of notice to all offset operators in all adjacent units.

(3) If the applicant requests the hearing in accordance with 15 CAR § 275-408, the application shall include proof of notice to all working interest owners in the subject unit and all offset operators in all adjacent established units including all working interest owners in the offset unit where the operator is the same as the applicant.

(f) Establishment of field rules.

(1) Unless otherwise specified below, 15 CAR § 275-101 shall apply to all hearings for the creation of field rules, as provided by 15 CAR § 275-226.

(2) The application shall include proof of notice to each owner, as defined in Arkansas Code § 15-72-102(9), within:

(A) The proposed unit in which the well is located; and

(B) All units offsetting the boundary line or lines of the proposed unit.

(3) The application shall include a geologic report of the proposed field, specifying the geologic setting of the proposed field and including at a minimum a:

(A) Completion report of the discovery and other wells located within the proposed field;

(B) Type geophysical log from a well in the proposed field; and

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book; amended April 13, 2008; amended December 14, 2008; amended July 17, 2009; amended July 1, 2016)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-103 Definitions {#sec-15-car-275-103 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-103}

15 CAR § 275-103. Definitions.

Unless the context otherwise requires, the words defined shall have the following meaning when found in this part, to wit:

(1) “Atmospheric pressure” means the pressure of air at the sea level, equivalent to about fourteen and seven-tenths pounds per square inch (14.7 psi);

(2) “Balance (gas)” means an instrument used for determining the specific gravity of gases by weighing methods;

(3) “Barometric pressure” means the pressure or weight of air determined by the use of a barometer at a given point;

(4) “Barrel” or “barrel of oil” means forty-two (42) United States gallons of oil at a test of sixty degrees Fahrenheit (60° F), with deductions for the full percent of basic sediment, water, and other impurities present, ascertained by centrifugal or other recognized and customary test;

(5) “Blowout” means a sudden or violent escape of crude oil or natural gas, as from a drilling well, when high formation pressure is encountered;

(6) “Blowout preventer” means a heavy casing head control filled with special gates or discs which:

(A) May be closed around the drill pipe; or

(B) Completely closes the top of the casing if the pipe is withdrawn;

(7)(A) “Bottom hole pressure” means the pressure in pounds per square inch at or near the bottom of an oil or gas well determined at the face of the producing horizon by means of a pressure recovery instrument, adopted and recognized by the oil and gas industry, which can be lowered into the bore of the well.

(B) In the case of gas wells or wells having no fluid in the well bore, it shall mean the pressure as calculated by adding the pressure at the surface of the ground to the calculated weight of the column of gas from the surface to the bottom of the hole;

(8) “Casing pressure” means the pressure built up between the casing and tubing when the casing and tubing are packed off at the top of the well;

(9) “Casinghead gas” means any gas or vapor, or both gas and vapor, indigenous to an oil stratum and produced from such stratum with oil;

(10) “Christmas tree” means an assembly of valves and fittings at the head of the casing of a well to control the flow; also spoken of as “well head connections”;

(11) “Circulation” means the passing of an approved fluid down through the drill stem and up to the surface in the process of rotary drilling in setting casing;

(12) “Combination well” means a well productive of both oil and gas:

(A) In commercial quantities from the same common source of supply; and

(B) Which has sufficient natural gas pressure to cause the gas to enter a pipeline carrying more than atmospheric pressure;

(13) “Commission” means the Oil and Gas Commission;

(14)(A) “Common source of supply” means the geographical area or horizon definitely separated from any other such area or horizon and which contains, or from competent evidence appears to contain, a common accumulation of oil or gas or both.

(B) Any oil or gas field or part thereof which comprises and includes any area which:

(i) Is underlaid; or

(ii) From geological or other scientific data or experiments or from drilling operations or other evidence appears to be underlaid by a common pool or accumulation of oil or gas or both oil and gas;

(15)(A) “Condensate” means the liquid produced by the condensation of a vapor or gas either:

(i) After it leaves the reservoir; or

(ii) While still in the reservoir.

(B) Condensate is often called distillate, drips, white oil., etc.;

(16) “Connate water” means water which:

(A) Was deposited with the deposition of solid sediments in an oil or gas reservoir; and

(B) Has not, since its deposition, existed as surface water at atmospheric pressure;

(17) “Conservation” means the conserving, preserving, guarding, or protecting the oil and gas resources of the state by obtaining the maximum efficiency with minimum waste in the production, transportation, processing, refining, treating, and marketing of the unrenewable oil and gas resources of the state;

(18) “Controlled gas field” means any common source of supply of natural gas discovered after January 1, 1937, or any field discovered prior to January 1, 1937, provided any pool therein has been discovered after January 1, 1937;

(19) “Controlled oil field” means any common source of supply of crude oil discovered after January 1, 1937, or any field discovered prior to January 1, 1937, provided any pool therein has been discovered after January 1, 1937;

(20) “Controlled production” means the production of oil or gas or both oil and gas from a controlled oil or gas field;

(21) “Core hole” means a hole drilled below the fresh water level for obtaining geological and structural information without penetrating a known producing formation in the area;

(22) “Crude oil” means petroleum oil, and other hydrocarbons, regardless of gravity, which:

(A) Are produced at the well in liquid form by ordinary production methods; and

(B) Are not the result of condensation of gas before or after it leaves the reservoir;

(23)(A) “Cubic foot of gas” means the volume of gas contained in one cubic foot (1 ft³) of space at the standard pressure base and the standard temperature base.

(B) The standard pressure base shall be fourteen and sixty-five hundredths pounds per square inch (14.65 psi) absolute and the standard temperature base shall be sixty degrees Fahrenheit (60° F);

(24) “Day” means a period of twenty-four (24) consecutive hours from 7:00 a.m. of one day to 7:00 a.m. of the following day;

(25) “Development” means any work which actively looks toward bringing in production, such as erecting rigs, building tankage, drilling wells, etc.;

(26) “Differential pressure” means the difference between:

(A) The tubing pressure and the flow-line pressure;

(B) The drop flow-line pressure;

(D) In the case of an orifice meter, the difference of the pressures on the upstream and the downstream sides of the orifice;

(E) A pressure measured with a differential gauge or with a manometer (U-tube);

(F) Any difference in pressure;

(27)(A) “Distillate” means a product of distillation of the fluid condensed from the vapor driven off in the still, such as gasoline, naphtha, kerosene, and light lubrication oils, the result of distillation of crude oil.

(B) Condensate is commonly referred to as distillate;

(28) “Division order” means a written statement, dated, duly signed by the owners, and delivered to the purchaser:

(A) Certifying and guaranteeing the interests of ownership of the production; and

(B) Directing payments according to those interests;

(29) “Dry gas” means natural gas obtained from sands that produce gas only, or natural gas obtained which does not contain the heavier fractions which may easily condense under normal atmospheric conditions, not casinghead gas;

(30) “Edge water” means water that holds the oil or gas, or both oil and gas, in higher structural position, usually encroaching on a pool as the oil or gas is removed;

(31)(A) “Field” means the general area which is underlaid or appears to be underlaid by at least one (1) pool.

(B) “Field” shall include the underground reservoir or reservoirs containing crude petroleum oil or natural gas, or both.

(C)The words “field” and “pool” mean the same thing when only one (1) underground reservoir is involved; however, “field”, unlike “pool”, may relate to two (2) or more pools;

(32) “Flowing well” means a well from which oil or gas flows naturally without pumping or other means of artificial lift;

(33) “Gas” means the natural gas obtained from gas or combination wells regardless of its chemical analysis;

(34) “Gas allowable” means the amount of natural gas authorized to be produced by order of the Oil and Gas Commission;

(35) “Gas assessment” means the assessment on each thousand cubic feet (1,000 ft³) of gas produced from a gas well to pay the costs incident to the administration of the rules of the Oil and Gas Commission;

(36) “Gas repressuring” means the introduction of gas or air into a common source of supply by artificial means in order to replenish, replace, or increase the gas energy causing the oil to flow out of the reservoir;

(37) “Gas sour” means gas which contains hydrogen sulfide in sufficient quantities to render it unfit for domestic or commercial use;

(38) “Gas well” means:

(A) A well which produces natural gas only;

(B) Any well capable of producing gas in commercial quantities and also producing oil from the same common source of supply but not in commercial quantities;

(D) A well that contains no liquid hydrocarbons in the reservoir;

(39) “Gas lift” means a method of injecting gas for lifting a liquid from the well to the surface;

(40) “Gas-oil ratio” means the number of cubic feet of gas at atmospheric pressure, as produced from an oil well or combination well, divided by the number of barrels (forty-two gallons (42 gals.)) of oil, the unit of time being a day of twenty-four (24) hours;

(41) “Illegal oil” means oil which has been produced within the State of Arkansas from any well during any time that well has produced in excess of the amount allowed by any rule or order of the Oil and Gas Commission, as distinguished from oil produced within the State of Arkansas from a well not producing in excess of the amount so allowed, which is “legal oil”;

(42) “Illegal gas” means gas which has been produced within the State of Arkansas from any well during any time that well has produced in excess of the amount allowed by any rule or order of the Oil and Gas Commission, as distinguished from gas produced within the State of Arkansas from a well not producing in excess of the amount so allowed, which is “legal gas”;

(43) “Illegal product” means any product of oil or gas, any part of which was processed or derived, in whole or in part, from illegal oil or illegal gas or from any product thereof as distinguished from “legal product”, which is a product possessed or derived to no extent from illegal oil or illegal gas;

(44)(A) “Indices of productive value” means the factors to be considered in ascertaining the productivity of all property in a common source of supply for the purpose of fixing the allowable production.

(B) These indices can mean, at the discretion of the Oil and Gas Commission:

(i) Acreage;

(ii) Gas-oil ratios;

(iii) Static reservoir pressures;

(iv) Flowing pressures;

(v) Fluid level drawdowns;

(vi) The well or wells; or

(vii) Any other pertinent factors;

(45) “Lease tank” means the tank or other receptacle into which oil is produced either directly from a well or from a well through:

(A) Gas separator;

(B) Gun barrel; or

(46) “Meter” means an instrument for measuring and recording the volume of gases or liquids;

(47) “Month” and “calendar month” means the period or interval of time from 7:00 a.m. on the first day of any month of the calendar to 7:00 a.m. of the first day of the next succeeding month of the calendar;

(48) “Mud-laden fluid” means any approved mixture of water and clay or other material as the term is commonly used in the industry;

(49) “Natural gasoline” means gasoline manufactured from casinghead gas or from any natural gas;

(50) “Oil” means crude oil or petroleum;

(51) “Oil allowable” means the amount of oil authorized to be produced by the order of the Oil and Gas Commission;

(52) “Oil assessment” means the assessment on each barrel of oil produced, from any field or reservoir, to pay the costs incident to the administration of the rules of the Oil and Gas Commission;

(53) “Oil pipeline” means oil free from water and basic sediment to the degree that it is acceptable for pipeline transportation and refinery use;

(54) “Oil well” means any well capable of producing oil in paying quantities that is not a gas well;

(55) “Operator” means any person who, duly authorized, is in charge of the development of a lease or the operation of a producing well;

(56) “Overage”, “over production” means the oil or gas produced in excess of the allowable as set by the Oil and Gas Commission;

(57) “Owner” means the person who has the right to:

(A) Drill into and produce from any field or reservoir; and

(B) Appropriate the production either for:

(i) Himself or herself; or

(ii) Himself or herself and another;

(58) “Period, allowable” means the month or day, as designated, in which allowable may be produced;

(59) “Permeability” means a measure, determined by scientific means, of the ability of fluid or gas to traverse the producing horizon in an oil or gas reservoir;

(60) “Person” means any:

(A) Natural person;

(B) Corporation;

(D) Partnership;

(E) Receiver;

(F) Trustee;

(G) Guardian;

(H) Executor;

(I) Administrator;

(J) Federal agency; or

(K) Representative of any kind;

(61) “Petroleum” means the natural untreated oil obtained from an oil well;

(62) “Pipeline” means any pipes above or below the ground used or to be used for the transportation of oil or gas;

(63) “Pipeline oil” means the same as “oil pipeline”;

(64) “Plug” means the:

(A) Abandoning of a producing or nonproductive well; and

(B) Stopping of the flow of water, gas, or oil in a well;

(65)(A) “Pool” means an underground reservoir containing a common accumulation of crude petroleum oil or natural gas or both.

(B) Each zone of a general structure which is completely separated from any other zone in the structure is covered by the term pool as used herein;

(66) “Porosity” means the:

(A) State or quality of being porous;

(B) Volume of pore space expressed as a percentage of the total volume of the rock mass; or

(67) “Potential” means the actual or properly computed daily ability of a well to produce oil or gas, either or both, as determined by the rules of the Oil and Gas Commission;

(68)(A) “Pressure base” means an absolute pressure agreed upon or set as a base for converting the volume of gas metered to correct volume.

(B) The standard pressure base shall be fourteen and sixty-five hundredths pounds per square inch (14.65 psi) absolute;

(69) “Pressure maintenance” means the:

(A) Reintroduction (in the early stages of field development) of gas or fluid produced from an oil, gas, or combination well to maintain the pressure of the reservoir; or

(B) Introduction of gas or fluid for the same purpose but obtained from an outside source;

(70) “Producer” means any person who owns, in whole or in part, a well capable of producing oil or gas or both in paying quantities;

(71) “Product” means any commodity made from oil or gas, and shall include:

(A) Refined crude oil;

(B) Crude tops;

(D) Processed crude petroleum;

(E) Residue from crude petroleum;

(F) Cracking stock;

(G) Uncracked fuel oil;

(H) Fuel oil;

(I) Treated crude oil;

(J) Residuum;

(K) Gas oil;

(L) Casinghead gasoline;

(M) Natural gas;

(N) Gasoline;

(O) Naphtha;

(P) Distillate;

(Q) Gasoline;

(R) Kerosene;

(S) Benzine;

(T) Wash oil;

(U) Waste oil;

(V) Blended gasoline;

(W) Lubricating oil; or

(X) Blends or mixture of oil with one (1) or more liquid products or byproducts derived from oil or gas, whether herein above enumerated or not;

(72) “Production, illegal” means the same as “illegal gas” and “illegal oil”;

(73) “Production interests” means the right to a specified part of production;

(74) “Proven oil or gas land” means that area which has been shown by development and geological information to be such that additional wells drilled thereon are reasonably certain to be commercially productive of oil or gas or both;

(75)(A) “Purchaser” means any person who directly or indirectly purchases, transports, takes, or otherwise removes production to his or her account from a well or lease.

(B) “Purchaser” is usually considered to be the person holding the division order;

(76) “Ratable take” means the same as “controlled production”;

(77) “Recompletion” means completion operations performed in a source of supply that is separate and distinct from the source of supply in which the well was successfully completed prior to the commencement of the current completion operations;

(78) “Refiner” means every person who has any part in the control or management of any operation by which the physical or chemical characteristics of oil or products are changed, but exclusive of the operations of:

(A) Passing oil through separators to remove gas;

(B) Placing oil in settling tanks to remove basic sediment and water;

(D) Generally cleaning and purifying oil;

(79) “Repressure” means to increase the reservoir pressure by the introduction of gas or fluid into the reservoir;

(80) “Reservoir pressure” means the same as “bottom hole pressure”;

(81) “Rock pressure” means the well head pressure on a gas well that has been closed long enough to attain a maximum;

(82) “Rotary drilling” means the hydraulic process of drilling, consisting of rotating a column of drill pipe to the bottom of which is attached a rotary drilling bit;

(83) “Run” means oil or gas removed from the lease;

(84) “Separator” means an apparatus for separating gas from oil with relative efficiency, as it is produced;

(85)(A) “Shut-in pressure” means the pressure noted at the wellhead when the well is completely shut in.

(B) “Shut-in pressure” is not to be confused with bottom hole pressure;

(86) “Spudding” means the initial step in drilling;

(87) “Storer” means every person as herein defined who stores, terminals, retains in custody under warehouse or storage agreements or contracts, oil which comes to rest in his or her tank or other receptacle under control of said storer, but excluding the ordinary lease stock of producers;

(88) “Taker” means the same as “purchaser”;

(89) “Tender” means a permit or certificate of clearance for the transportation of oil, gas, or products approved and issued or registered under the authority of the Oil and Gas Commission;

(90) “Tendership” means the production delivered from one person to another;

(91) “Topping plant” means a refinery designed to remove only the gasoline and kerosene fractions from oil;

(92) “Trap pressure” means pressure held at the oil and gas separator;

(93) “Transporter” means and includes any:

(A) Common carrier by:

(i) Pipeline;

(ii) Barge;

(iii) Boat or other water conveyance; or

(iv) Truck or other conveyance except railroads; and

(B) Person transporting oil by:

(i) Pipeline;

(ii) Barge;

(iii) Boat or other water conveyance; or

(iv) Truck and other conveyance;

(94) “Tubing” means the conduit through which oil or gas is removed from a well;

(95) “Vacuum” means pressure which is reduced below the pressure of the atmosphere;

(96) “Volatile” means easily wasting away by evaporation;

(97)(A) “Waste” means, in addition to its ordinary meaning, “physical waste” as that term is generally understood in the oil and gas industry.

(B) It shall include:

(i) The inefficient, excessive, or improper use or dissipation of reservoir energy, and the locating, spacing, drilling, equipping, operating, or producing of any oil or gas well or wells in a manner which results, or tends to result, in reducing the quantity of oil or gas ultimately to be recovered from any pool in this state;

(ii) The inefficient storing of oil, and the locating, spacing, drilling, equipping, operating, or producing of any oil or gas well or wells in a manner causing, or tending to cause, unnecessary or excessive surface loss or destruction of oil or gas;

(iii) Abuse of the correlative rights and opportunities of each owner of oil and gas in a common reservoir due to nonuniform, disproportionate, and unratable withdrawals causing undue drainage between tracts of land;

(iv) Producing oil or gas in such manner as to cause unnecessary water channeling or coning;

(v) The operation of any oil well or wells with an inefficient gas-oil ratio;

(vi) The drowning with water of any stratum or part thereof capable of producing oil or gas;

(vii) Underground waste however caused and whether or not defined;

(viii) The creation of unnecessary fire hazards;

(ix) The escape into the open air from a well producing both oil and gas, of gas in excess of the amount which is necessary in the efficient drilling or operation of the well;

(x) The use of gas for the manufacture of carbon black; and

(xi) Permitting gas produced from a gas well to escape into the air;

(98) “Water cone” means the creation of irregularly intruding water by allowing a well to produce too rapidly;

(99) “Well log” means an electrical, or any other type of survey, made for the purpose of ascertaining the strata through which a well bore has penetrated;

(100) “Wildcat well” means a well drilled outside the geological confines of proven production; and

(101) “Workover” means work of a remedial nature performed within the vertical confines of the same source of supply.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-104 Enforcement procedures {#sec-15-car-275-104 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-104}

15 CAR § 275-104. Enforcement procedures.

(a) Definitions. As used in this section:

(1) “Commission” means the Oil and Gas Commission, on which the Director of Production and Conservation serves as secretary, but is a nonvoting member;

(2) “Director” means the Oil and Gas Commission Director of Production and Conservation;

(3) “Regulated entity” means all operators, owners, producers, or persons subject to Oil and Gas Commission regulatory authority; and

(4) “UIC” means the Underground Injection Control program of the federal Safe Drinking Water Act, 42 U.S.C. § 300f et seq.

(b) Any regulated entity engaged in the drilling, operation, or plugging of any production, injection, or other well or drill hole regulated by the Oil and Gas Commission, or the operation of any crude oil or gas production or injection facility, or the operation of any natural gas line or crude oil flowline regulated by the commission, or transporter by tank truck of any oilfield production or completion fluid, or seismic activity, or any other activity regulated by the commission, is subject to this section for violation of any:

(1) Oil, gas, and/or brine statutes; or

(2) Any rule or permit condition of the commission.

(c) In accordance with Arkansas Code § 15-72-103(c) or § 15-76-303(c), any person knowingly and willfully aiding or abetting any other person in the violation of any statute relating to the conservation of oil, gas, and/or brine, or the violation of any provision of the state oil, gas, and/or brine statutes, or any rule, order, or permit condition, shall be subject to the same penalties as are prescribed herein for the regulated entity.

(d) Notice of noncompliance.

(1) A notice of noncompliance may be issued when any regulated entity is in noncompliance with any requirement of the Arkansas oil, gas, and/or brine statutes, or rules, orders, or any permit condition, and that:

(A) The noncompliance was not caused by the regulated entity’s deliberate action;

(B) Any action necessary to abate the noncompliance was commenced immediately and was or will be completed within a specified date certain, as established by the Director of Production and Conservation or his or her designee not to exceed thirty (30) days from the date of the determination that the regulated entity was determined to be in noncompliance; and

(C) The noncompliance has not caused and cannot reasonably be expected to cause significant environmental harm or damage to property.

(2)(A) The notice of noncompliance shall be documented in writing and delivered via first-class mail to the regulated entity or to the regulated entity’s representative as reported on the commission Form 1 Organization Report.

(B) The written notification shall indicate the:

(i) Nature and circumstances of the noncompliance; and

(ii) Time within which and the means by which the noncompliance is to be abated.

(3) If abatement was not completed as specified in the written notification, the director or his or her designee may issue a formal notice of violation in accordance with subsection (e) of this section, below.

(4) The provisions of this subsection (d) shall not apply to the following types of incidents, which may require a notice of violation to be issued in accordance with subsection (e) of this section, below:

(A) Conducting any regulated activity specified in subsection (b) of this section, above, prior to issuance or reissuance of the appropriate commission permit or authority;

(B) Operating an annular or casing injection/disposal well or a well with pressure on the annulus;

(D) Failure to establish mechanical integrity on any UIC well prior to operation, or failure to repair any UIC well following failure of mechanical integrity;

(E) Commencing any work or activity on a well or its related production facility or well site that has been placed in the Abandoned and Orphan Well Plugging Program;

(F) Failure to provide emergency response for a crude oil or saltwater spill;

(G) Improper discharge or disposal of produced fluids; or

(H) Operating a well in violation of spacing requirements or permit conditions.

(e) Notice of violation or violations.

(1)(A) A notice of violation may be issued by the director or his or her designee when any regulated entity is in violation of any:

(i) Requirements of the Arkansas oil, gas, and/or brine statutes, rules, orders; or

(ii) Permit conditions of the commission.

(B) Unless otherwise determined by the commission after notice and a hearing, a regulated entity shall not be held responsible by the commission for violations of oil, gas, and/or brine statutes, rules, or permit conditions of the commission in the absence of the issuance of an underlying notice of violation.

(2) The notice of violation shall be in writing and contain:

(A) A statement regarding the nature of the violation, including a citation to the specific section of the oil, gas, and/or brine statutes, or any rule, order, or permit condition of the commission alleged to have been violated;

(B) The suggested action needed to abate the violation including any appropriate remedial measures to prevent future violations;

(D) A notice of any civil penalties, as specified in subsection (g) of this section, below, the director will request to be issued by the commission; and

(E) A notice of any civil penalties for violations of natural gas line regulations under United States Department of Transportation, Office of Pipeline Safety jurisdiction in accordance with appropriate federal regulation specified in 49 C.F.R. § 190.223, the director will request to be issued by the commission.

(3) The notice of violation may include a well, lease, or unit cessation requirement for the following types of violations:

(A) Violation of production allowable;

(B) Failure to maintain required well-specific performance bond;

(C) Drilling or operating, without a commission permit or permit transfer, a well required to be permitted or transferred;

(D) Operating a well that has been determined to be abandoned by the commission;

(E) Failure to plug a leaking well or a well ordered to be plugged by the commission;

(F) Operating an annular or casing injection/disposal well;

(G) Operating a UIC Class II or V well with a failed mechanical integrity test;

(H) Operating a UIC Class II or V well with pressure on the annulus indicating tubing and/or casing failure;

(I) Failure to provide emergency response or remediate a crude oil or produced water spill;

(J) Improper disposal or discharge of produced fluids; or

(K) Any other violation for which a cessation requirement is authorized by an oil, gas, and/or brine statute, rule, order, or permit condition.

(4) The notice of violation may also include a state-wide cessation requirement for the following types of violations:

(A) Failure to maintain required blanket financial assurance as specified in 15 CAR § 275-202;

(B) Failure to pay annual well fees as specified in 15 CAR § 275-202;

(D) Failure to comply with the provisions of 15 CAR § 275-229 or 15 CAR § 275-503; or

(E) Any other violation for which a state-wide cessation requirement is authorized by an oil, gas, and/or brine statute, rule, order, or permit condition.

(5) The director or his or her designee shall send via certified mail the notice of violation to the regulated entity, or the regulated entity’s representative as reported on the commission Form 1 Organization Report, charged with the violation or violations, or provide personal delivery of a copy of the notice to the regulated entity, or the regulated entity’s representative.

(6)(A) The regulated entity charged with the violation or violations may request a director’s review of the notice of violation and provide the director, in writing, any information in mitigation of the violation or violations on or before thirty (30) calendar days of the mailing or personal delivery of the original notice of violation, unless a shorter time period is specified in the notice of violation for instances where there is a condition that creates an imminent danger to the health or safety of the public or threatens significant environmental harm or damage to the property.

(B) Such written information may include a proposed alternative to the required action needed to abate the violation or violations.

(7) During the review, the director may consider any of the following criteria in reaching a final director’s decision regarding the violation or violations:

(A) The regulated entity’s history of previous violations, including violations at other locations and under other permits;

(B) The seriousness of the violation, including any irreparable harm to the environment or damage to property;

(D) The existence of any additional conditions or factors in aggravation or mitigation of the violation, including information provided by the regulated entity.

(8) Upon completion of the review, the director shall issue a final director’s decision to:

(A) Affirm the violation;

(B) Vacate the violation;

(D) Establish probationary or permanent modification or conditions to any underlying permit related to the violation, which may include special monitoring or reporting requirements; or

(E) Enter into a settlement agreement to extend the amount of time provided to complete remedial actions necessary to abate the violation or reduce the amount of the requested assessed civil penalty.

(9)(A) The final director’s decision shall be delivered to the regulated entity, or the regulated entity’s representative, as reported on the commission Form 1 Organization Report, via first-class mail.

(B) The final director’s decision may be appealed to the commission by filing an application in accordance with 15 CAR §§ 275-101 and 275-102 and other applicable hearing procedures.

(C) The application to appeal the final director’s decision is required to be received by the director within thirty (30) days of the mailing of the final director’s decision.

(D) The application shall state the reason for the appeal and shall be scheduled to be heard by the commission in accordance with 15 CAR §§ 275-101 and 275-102 and other applicable hearing procedures.

(10) A notice of violation for which a director’s review has not been requested shall become a final administrative decision of the commission thirty (30) days following the mailing of the notice of violation.

(11) A final director’s decision not appealed to the commission within thirty (30) days of mailing of the final director’s decision shall become a final administrative decision of the commission.

(12)(A) All violations specified in a notice of violation or violations which have become a final administrative decision in accordance with subdivision (e)(10) of this section, a final director’s decision which has become a final administrative decision of the commission in accordance with subdivision (e)(11) of this section, or by order of the commission, shall be fully abated within the time frame specified in the original:

(i) Notice of violation;

(ii) Final director’s decision; or

(iii) Order of the commission.

(B) No further permits or authorities shall be issued to the regulated entity until all outstanding violations specified in a notice of violation which has become a final administrative decision in accordance with subdivision (e)(10) of this section, a final director’s decision which has become a final administrative decision of the commission in accordance with subdivision (e)(11) of this section, or by order of the commission have been fully abated.

(f) In addition to the issuance of a notice of violation, the director may initiate further enforcement proceedings, as provided for in statute, as follows:

(1) Assessment of a civil penalty as provided in Arkansas Code § 15-71-114, § 15-72-103, § 15-72-202, or § 15-76-303;

(2) The revocation of a certificate of clearance on a state-wide basis, as provided for in Arkansas Code § 15-71-110(d)(11);

(3) The filing of a civil complaint in a court of competent jurisdiction in the county where the violation occurred, as provided for in Arkansas Code § 15-72-108 or § 15-76-304; or

(4) The filing of a criminal complaint in any court of competent jurisdiction, as provided for in Arkansas Code § 15-71-114, § 15-72-104, or § 15-76-303.

(g) Civil penalties.

(1)(A) The director shall determine whether to request the assessment of civil penalties based on failure to comply with the applicable abatement requirements for violations issued under subdivisions (g)(2) and (3) of this section below.

(B) The director shall determine whether to request the assessment of civil penalties for violations issued under subsections (g)(4) and (5) of this section, below.

(C) If a civil penalty is requested by the director, the regulated entity may voluntarily agree to the assessment and pay the civil penalty as requested or modified by the director, or the director or his or her designee may file an application, in accordance with 15 CAR §§ 275-101 and 275-102, and other applicable hearing procedures, to request the issuance of the requested civil penalty by the commission.

(D)(i) The maximum amount of the director’s requested civil penalty shall be computed as provided in subdivisions (g)(2) – (5) of this section, below.

(ii) However, the commission:

(a) Is not bound by the director’s request, or the amounts provided below; and

(b) May impose civil penalties of up to the maximum amounts permitted by law.

(2) Administrative violations.

(A) Defined as failure to file required reports and forms and to provide required notices (excluding spill notice), including, but not limited to, regulated activities such as the failure to:

(i) File production and well reports or other reports required by commission rules, orders, or permit conditions;

(ii) Notify the commission before the setting of surface casing or the plugging of a well;

(iii) Maintain required performance bond in force for the wells under permit; or

(iv) Pay annual well fees within the specified time.

(B) The director may request the assessment of up to one thousand dollars ($1,000) per administrative violation and up to one thousand dollars ($1,000) per day for each day the violation remains unabated after the specified compliance date.

(i) No previous violation of the same rule, two hundred fifty dollars ($250);

(ii) One (1) previous violation of the same rule, five hundred dollars ($500);

(iii) Two (2) or more previous violations of the same rule, one thousand dollars ($1,000); and

(iv) The fourth and each subsequent violation of the same rule shall be considered a significant violation in accordance with subdivision (g)(4) of this section, below.

(D) The time frame used for determining previous violations shall be limited to the regulated entity’s violation record for the preceding three (3) full calendar years before the issuance of the violation.

(3) Operating violations.

(A) Defined as:

(i) Failure to maintain compliance with commission rules on well drilling and operation, and production facility, pipeline, and seismic operations; and/or

(ii) Commencing operations requiring a permit prior to issuance or reissuance of the required permit or authority.

(B) These operations include, but are not limited to, regulated activities such as:

(i) Operating a well or natural gas pipeline system without the proper permit or transfer of ownership;

(ii) Failure to maintain a well or crude oil flow line in a leak-free condition;

(iii) Failure to comply with nonjurisdictional natural gas pipeline requirements;

(iv) Failure to notify of a spill occurrence;

(v) Failure to maintain containment dikes; or

(vi) Operating an exploration and production fluid transportation system without a proper permit.

(C) Multiple incidents of the same violation against a regulated entity on the same occasion shall not be considered separate violations.

(D) The director may request the assessment of up to two thousand five hundred dollars ($2,500) per operating violation and up to two thousand five hundred dollars ($2,500) per day for each day the violation remains unabated after the specified compliance date, with the exception that operating violations as specified in Arkansas Code § 15-76-303 are limited to a maximum of one thousand dollars ($1,000) per operating violation.

(E) The per operating violation civil penalty shall be calculated as follows:

(i) No previous violation of the same rule, five hundred dollars ($500);

(ii) One (1) previous violation of the same rule, seven hundred fifty dollars ($750);

(iii) Two (2) or more previous violations of the same rule, one thousand dollars ($1,000); and

(iv) The fourth and each subsequent violation of the same rule shall be considered a significant violation in accordance with subdivision (g)(4) of this section, below.

(F) The time frame used for determining previous violations shall be limited to the regulated entity’s violation record for the preceding three (3) full calendar years before the issuance of the violation.

(G) If the violation:

(i) Had a low degree of probability to cause environmental impact to soil and/or land surface, vegetation or crops, surface water, groundwater, livestock or wildlife, add two hundred fifty dollars ($250);

(ii) Had a high degree of probability to cause environmental impact to soil and/or land surface, vegetation or crops, surface water, groundwater, livestock or wildlife, add five hundred dollars ($500); or

(iii) Caused environmental impact to soil and/or land surface, vegetation or crops, surface water, groundwater, livestock or wildlife, add one thousand dollars ($1,000).

(H) If the violation created a hazard to the safety of any person, such as the contamination of a potable water well or emission of hydrogen sulfide gas, add two thousand dollars ($2,000).

(4)(A) Except as limited in Arkansas Code § 15-76-303, or as otherwise provided in subdivision (g)(5) or subdivision (g)(6) of this section, below, significant violations may result in a request by the director or his or her designee of a civil penalty of up to two thousand five hundred dollars ($2,500) per violation and up to two thousand five hundred dollars ($2,500) per day for each day of the violation for the following types of violations:

(i) Failure to comply with the provisions of 15 CAR § 275-105;

(ii) Failure to comply with well spacing provisions;

(iii) Operating a UIC well without a proper permit;

(iv) Operating an annular or casing injection/disposal well;

(v) Operating a UIC well prior to establishing mechanical integrity;

(vi) Operating a UIC well with a failed mechanical integrity test;

(vii) Operating a UIC well with pressure on the annulus;

(viii) Failure to provide emergency response or remediate a crude oil or produced water spill; or

(ix) The improper disposal or discharge of produced fluids.

(B) The per violation civil penalty shall be computed as follows:

(i) An initial amount of one thousand dollars ($1,000);

(ii) One (1) or more previous violations of the same type, add five hundred dollars ($500) per violation;

(iii) If the violation caused environmental impact to surface water, ground water, or wildlife, add one thousand dollars ($1,000); or

(iv) If the violation created a hazard to the safety of any person, such as the contamination of a potable water well or emission of hydrogen sulfide gas, add one thousand five hundred dollars ($1,500).

(C) The time frame used for determining previous violations shall be limited to the regulated entity’s violation record for the preceding three (3) full calendar years before the issuance of the violation.

(5) In accordance with Arkansas Code § 15-72-103, the director or his or her designee may request a civil penalty of up to one hundred thousand dollars ($100,000) for any person who transports a liquid or other substance and violates a rule or order of the commission by dumping or disposing of the liquid or other substance improperly or without authorization at a well or well site.

(6) The director or his or her designee may request any amount in civil penalties authorized by applicable federal law for violations of the United States Department of Transportation, Office of Pipeline Safety jurisdictional natural gas line requirements.

(h)(1) All civil penalties assessed and paid to the commission shall be deposited in the commission operating fund.

(2) Additionally, all civil penalties assessed and paid for violations specified in Arkansas Code § 15-72-202 shall be turned into the general fund of the county where the violation occurred to be used on roads, bridges, and highways at the discretion of the county court.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: new rule September 14, 2008; amended July 17, 2009; amended October 24, 2009; amended July 29, 2011; amended February 17, 2012; amended January 20, 2014)" Authorities: Arkansas Code § 15-71-110; Arkansas Code § 15-72-103; Arkansas Code § 15-76-303

15 CAR § 275-105 [Reserved] {#sec-15-car-275-105 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-105}

15 CAR § 275-105. [Reserved].

15 CAR § 275-106 Determination of natural gas well categories for severance tax purposes {#sec-15-car-275-106 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-106}

15 CAR § 275-106. Determination of natural gas well categories for severance tax purposes.

(a) Applicability.

(1) In accordance with Arkansas Code § 26-58-128, the Director of the Oil and Gas Commission shall determine the well categories for all gas production wells, which will be used by the Department of Finance and Administration to determine the appropriate severance tax rate for each well.

(2) All gas production wells under the jurisdiction of the Oil and Gas Commission are subject to the provisions of this section.

(b) Definitions. As used in this section:

(1) “Commission” means the Oil and Gas Commission, on which the Oil and Gas Commission Director of Production and Conservation serves as secretary, but is a nonvoting member;

(2) “Conventional gas well” means a gas well that is not classified as a high-cost gas well;

(3) “Director” means the Oil and Gas Commission Director of Production and Conservation;

(4) “High-cost gas well” means a gas well that:

(A) Produces gas from any shale formation, including but not limited to:

(i) The Fayetteville Shale, Woodford Shale, Moorefield Shale, and the Chattanooga Shale; or

(ii) Their stratigraphic equivalents as described in published stratigraphic nomenclature recognized by the Arkansas Geological Survey;

(B) Produces gas from any completion that is located at a depth of more than twelve thousand five hundred feet (12,500’) below the surface of the earth, where the term “depth” means the length of the maximum continuous drilling string of drill pipe used between the drill bit face and the drilling rig’s Kelly bushing;

(i) Has previously been determined to be a low permeability formation by:

(a) Oil and Gas Commission orders or field rules for:

(1) Booneville and Chismville (84-2003-07);

(2) Gragg (89-2004-07);

(3) Waveland (86-2004-07);

(4) Rich Mountain (304-2006-09);

(5) Mansfield (28-2003-03);

(6) Witcherville; and

(7) Excelsior (103-2005-07); and

(b) 15 CAR § 275-231;

(ii) Is determined by the Director of Production and Conservation to have an estimated in situ permeability of one-tenth millidarcy (0.1 mD) or less; or

(iii) Is determined to be a tight gas formation by field rule, general rule, or orders approved by the Oil and Gas Commission and issued by the Director of Production and Conservation;

(D) Produces gas from a geopressured brine; or

(E) Produces occluded gas from a coal seam;

(5) “Marginal conventional gas well” means a conventional gas well which is incapable of producing more than two hundred fifty (250) Mcf per day, from all zones producing in such well, as determined by the sum of the individual deliverability rates for each zone, using one (1) of the current wellhead deliverability rate methodologies described in subsection (h) of this section, below;

(6) “Marginal high-cost gas well” means a high-cost gas well which is incapable of producing more than one hundred (100) Mcf per day from all zones producing in such well as determined by the sum of the individual deliverability rates for each zone, using one (1) of the current wellhead deliverability rate methodologies described in subsection (h) of this section, below; and

(7) “New discovery gas well” means any conventional gas well for the period commencing on the date of first production and ending on the date that is twenty-four (24) consecutive calendar months following the date of first production.

(c)(1) On or before January 1, 2009, the Director of Production and Conservation shall determine the initial well category for each existing gas-producing well in the state.

(2) If a well contains two (2) or more separately metered producing zones (sources of supply), and one (1) or more of the producing zones are different categories, the well category shall be based on which zone in the well produces the larger percentage of the total well production, based on the most recent back pressure test methodology specified in 15 CAR § 275-405.

(3) On or before January 1, 2009, the Director of Production and Conservation shall notify each permit holder of each existing well’s determination as a:

(A) High-cost gas well, including whether it is a high-cost gas well producing gas from the date of first production and for a minimum period of thirty-six (36) consecutive calendar months following the date of first production, unless a longer time period is granted by the department in accordance with Arkansas Code § 26-58-127;

(B) Marginal conventional gas well;

(D) New discovery gas well; or

(E) Conventional gas well.

(d)(1)(A) After January 1, 2009, the Director of Production and Conservation shall determine, at the time of permitting each new well, the appropriate well category as specified in subsection (c) of this section, above, which shall be effective the date of first production from the well.

(B) This well category determination, made at the time of the initial new well permit issuance or as amended in accordance with this subsection or subsection (g) of this section, below, shall determine the well category throughout the life of that well.

(2) Once a permit is issued, if a well is completed in two (2) or more separately metered producing zones (sources of supply), and one (1) or more of the producing zones are different categories, with respect to a conventional gas well or a high-cost gas well, the well category shall be based on which zone in the well produces the larger percentage of the total well production, based on the initial back pressure tests required by 15 CAR § 275-405.

(3) The well category determination shall determine the category for that well throughout the life of that well, regardless if other zones are produced within the well at a later date, until such time as the well qualifies as a:

(A) Marginal conventional gas well; or

(B) Marginal high-cost gas well.

(e) Following the well category determination for all existing wells on January 1, 2009, and the ongoing categorization for all new wells after January 1, 2009, the permit holder may request at any time, on a form prescribed by the Director of Production and Conservation, another well category determination with respect to the well category definitions specified in subsection (b) of this section, above, in accordance with the application procedures specified in subsection (i) of this section, below.

(f)(1) Upon submission of the application and supporting documentation or other required information, the Director of Production and Conservation shall make a determination within fifteen (15) calendar days from the receipt of such application.

(2) The effective date of the well category determination request shall automatically be the:

(A) First day of the next month following the postmark date the application was mailed to the Director of Production and Conservation; or

(B) Date of the Director of Production and Conservation’s office date stamp, if delivered in person to the Director of Production and Conservation.

(3) If approved by the Director of Production and Conservation, the application shall be sent via first-class mail to the permit holder and a copy forwarded to the department.

(4)(A) If the application is denied by the Director of Production and Conservation, the permit holder may appeal the Director of Production and Conservation’s determination to the commission by filing an application in accordance with 15 CAR §§ 275-101 and 275-102, and other applicable hearing procedures.

(B)(i) If the permit holder does not appeal the denial, and the date of the Director of Production and Conservation’s denial occurs after the effective date of the well determination request as defined in subdivision (f)(2) of this section, above, the permit holder may be subject to additional payment provisions in accordance with department procedures.

(ii) If the permit holder appeals the denial, the effective date of the well categorization request shall remain in effect pending the outcome of the appeal.

(g)(1) If following a review of completion reports, monthly production reports, the applicable wellhead deliverability rate, utilizing one (1) of the current methodologies specified in subsection (h) of this section, below, or other information, the Director of Production and Conservation determines a well is not correctly categorized, the Director of Production and Conservation shall determine the correct well category and notify the permit holder.

(2) The corrected well category determination shall become effective on the first day of the month following the month in which the Director of Production and Conservation notifies the permit holder of the corrected well category determination, unless the permit holder files an appeal of the Director of Production and Conservation’s decision in accordance with 15 CAR §§ 275-101 and 275-102, and other applicable hearing procedures.

(h) All existing well category determinations under subsection (c) of this section and all new well category determinations under subsection (d) of this section shall be made on the basis of one (1) of the following current wellhead deliverability rate methodologies:

(1) Establishing cumulative deliverability of the well utilizing test methodologies specified in 15 CAR § 275-405; or

(2)(A) Calculating the cumulative deliverability of the well utilizing the most recent six-month average daily rate of production for the well under actual operating conditions by dividing the total gas reported for the well by the number of days the well produced during the applicable six-month period.

(B) However, this well category determination method is not applicable for wells subject to an exceptional location penalty.

(i) Well category determination and application procedures.

(1) High-cost gas well.

(A)(i) The high-cost gas well category shall be assigned to all existing wells on January 1, 2009, which satisfy the definition of a high-cost gas well in accordance with subdivision (b)(4) of this section, above.

(ii) If on that date the high-cost gas well has a reported date of first production on or after January 1, 2006, the well shall automatically qualify for a cost recovery period for a period of thirty-six (36) consecutive calendar months following the date of first production, unless a longer time period is granted by the department in accordance with Arkansas Code § 26-58-127.

(B)(i) On or after January 1, 2009, the high-cost gas well category shall be assigned to all newly permitted wells that satisfy the definition of a high-cost gas well in accordance with subdivision (b)(4) of this section, above, at the time of well categorization in accordance with subsections (d) and (g) of this section, above.

(ii) The well shall automatically qualify for a cost recovery period for a period of thirty-six (36) consecutive calendar months following the date of first production, unless a longer time period is granted by the department in accordance with Arkansas Code § 26-58-127.

(C)(i) At the conclusion of the cost recovery period, specified in subdivisions (i)(1)(A) and (B) of this section above, the well shall:

(a) Automatically be reclassified as a high-cost gas well no longer subject to the tax rate for the cost recovery period; and

(b) Be subject to the applicable severance tax rate specified in Arkansas Code § 26-58-111(5)(D) unless an application is made for classification as a marginal high-cost gas well in accordance with subdivision (i)(3)(B) of this section, below.

(ii) The effective date of the automatic reclassification shall be the first day of the month following the month in which the specified recovery period expired.

(2) New discovery gas well.

(A) The new discovery gas well category shall be assigned to all existing conventional wells on January 1, 2009, which as of that date have a reported date of first production on or after January 1, 2007.

(B)(i) The new discovery gas well category shall be automatically assigned to all newly permitted conventional wells on or after January 1, 2009, at the time of well categorization in accordance with subsections (d) and (g) of this section, above.

(ii) The well category determination shall remain in effect for twenty-four (24) consecutive calendar months following the date of first production.

(C)(i) At the conclusion of the twenty-four (24) consecutive calendar months following the date of first production, the new discovery gas well determination shall automatically terminate.

(ii) The effective date of the automatic termination shall be the first day of the month following the month in which the actual date of termination occurred.

(iii) The well shall be automatically reclassified as a conventional gas well subject to the applicable severance tax rate specified in Arkansas Code § 26-58-111(5)(D), unless application is made for classification as a marginal conventional gas well in accordance with subdivision (i)(3)(B) of this section, below.

(3) Marginal conventional gas well and marginal high-cost gas well.

(A) The applicable marginal gas well category shall be assigned to all existing conventional gas wells and high-cost gas wells on January 1, 2009, that qualify as either a marginal conventional gas well or a marginal high-cost gas well and which, as of that date, do not qualify as either a:

(i) New discovery gas well during the cost recovery period set forth in subdivisions (i)(2)(A) and (B), above; or

(ii) High-cost gas well during the cost recovery period set forth in subdivisions (i)(1)(A) and (B) above.

(B)(i) When a conventional gas well qualifies as a marginal conventional gas well, or a high-cost gas well qualifies as a marginal high-cost gas well, a permit holder may apply to the Director of Production and Conservation for a marginal conventional gas well or marginal high-cost gas well category determination.

(ii) The request shall be on a form prescribed by the Director of Production and Conservation and shall include a copy of the most recent well head deliverability rate determination for all producing zones based on one (1) of the current wellhead deliverability rate methodologies specified in subsection (h) of this section, above.

(C) The effective date of the applicable marginal gas well determination shall be the first day of the month following the month in which the permit holder’s application was received in accordance with subsection (f) of this section above.

(D)(i) A permit holder shall immediately notify the Director of Production and Conservation in writing when a well, which has been previously determined to be a marginal conventional gas well no longer qualifies as a marginal conventional gas well, or a marginal high-cost gas well no longer qualifies as a marginal high-cost gas well.

(ii) When a previously determined marginal conventional gas well becomes capable of producing more than two hundred fifty (250) Mcf per day over a thirty-day period or a well previously determined to be a marginal high-cost gas well becomes capable of producing more than one hundred (100) Mcf per day over a thirty-day period, the permit holder shall submit a copy of the most recent well head deliverability rates for each producing zone in the well based on one (1) of the current wellhead deliverability rate methodologies specified in subsection (h) of this section, above, along with the required written notice to the Director of Production and Conservation.

(4) Wells not classified as a high-cost gas well, new discovery gas well, marginal conventional gas well, or marginal high-cost gas well, as described above, shall be automatically classified as a conventional gas well subject to the severance tax rate specified in Arkansas Code § 26-58-111(5)(D).

(j) Failure to comply with any provision of this section may result in the initiation of enforcement actions in accordance with 15 CAR § 275-104, including the assessment of a civil penalty not to exceed two thousand five hundred dollars ($2,500) per day for each day of the violation.

History

Codification Notes: “Mcf” means one thousand cubic feet (1,000 ft3).This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: new rule November 16, 2008; amended June 5, 2009)" Authority: Arkansas Code § 15-72-103

Subpart 2

15 CAR § 275-201 Application to drill a production well {#sec-15-car-275-201 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-201}

15 CAR § 275-201. Application to drill a production well.

(a) Definitions.

(1)(A) “Deepen” for a cased well means an operation whereby a well is drilled to a measured depth below the cement casing shoe.

(B) For an open hole completion, “deepen” means an operation whereby a well is drilled below the original measured depth of the well;

(2) “Drill” means the commencement of an operation to either set conductor pipe or the moving in a drilling rig capable of drilling to a depth to set the requisite amount of surface casing and spudding the well, if conductor pipe is not used;

(3) “Permit holder” means the person to whom the permit is issued and is responsible for all regulatory requirements relative to the production well;

(4) “Production well” means a well drilled, deepened, or reentered after plugging, for:

(A) The exploration or production of oil and/or gas or brine; or

(B) A water supply for use in connection with an enhanced oil recovery project;

(5) “Reenter” means an operation whereby access to a previously plugged wellbore is reestablished for any purpose including replugging;

(6)(A) “Shale operations” means drilling activities relating to the production of gas and other petroleum hydrocarbons directed at an unconventional shale gas formation in a county listed in 15 CAR § 275-230(c) or 15 CAR § 275-230(d).

(B) “Shale operations” does not include:

(i) The periodic inspection, maintenance, or repair of completion activities;

(ii) Preparatory activities such as inspection, surveying, or staking; or

(iii) Drilling additional wells, redrilling, or recompletion operations on an existing drilling pad if the operator does not expand the existing pad.

(7) “Spud” means the commencement of drilling a wellbore to a depth to set the requisite amount of surface casing.

(b) Permit application procedures for a permit to drill, deepen, or reenter a production well.

(1)(A) No person shall drill, deepen, or reenter a plugged production well without a permit.

(B) A copy of the permit shall be posted on site prior to a well being spud or the commencement of deepening or reentering operations.

(2)(A) The permit holder is required to provide notice to the surface owner in accordance with Arkansas Code § 15-72-203.

(B) If notice is required in accordance with Arkansas Code § 15-72-203(c) and entry upon the surface owner’s surface estate is required on or after the effective date of this rule, the notice shall contain:

(i) The proposed date shale operations will commence;

(ii) The location of the proposed well and the pad location, including the section, township, range, and plat of the pad location, if available;

(iii) A statement that the:

(a) Permit holder has a pending or approved drilling permit for the proposed shale operations on the surface owner's property; and

(b) Permit shall be available for inspection by the surface owner on request by the surface owner; and

(iv) The name, address, telephone number, fax number, and electronic mailing address of the permit holder or the permit holder’s agent.

(C) The notice shall be sent by certified United States Postal Service or delivered personally to the surface owner at the address of the surface owner stated in the public records of the county collector of the county in which the surface owner’s property is located at least fourteen (14) days before the permit holder proposes to begin shale operations on the surface owner’s property.

(D) After written notice of the permit holder’s intent to begin shale operations is given under this subsection, a permit holder is not required to give any other notice to begin, conduct, or complete shale operations on the surface owner’s property.

(E) Written notice under this subsection is:

(i) Presumed delivered three (3) days after mailing by certified mail; or

(ii) Effective immediately upon hand delivery.

(F) Written notice is not required:

(i) For emergency situations in which the shale operations are required to protect the public health and safety or the environment; or

(ii) If a surface owner has a contractual relationship with a permit holder or the permit holder’s agent that specifies when or how the permit holder shall give notice regarding the beginning of shale operations.

(G) After receipt of a written notice of the permit holder’s intent to begin shale operations under this subsection, the surface owner shall not make alterations to a proposed drilling location to interfere with the shale operations for which the surface owner received the notice.

(H) The provisions of subdivisions (b)(2)(A) — (F) of this section, above, do not supersede, modify, or supplant the notice provisions of 15 CAR § 275-229.

(3)(A) The permit holder shall notify the appropriate Oil and Gas Commission regional office by telephone or other approved method a minimum of twenty-four (24) hours prior to a well being spud or the commencement of deepening or reentering operations.

(B) Commission staff may conduct site inspections as deemed necessary.

(4)(A) No production well may be drilled at a surface location other than that specified on the permit, except that if a permit holder has commenced drilling operations and the production well is lost due to adverse drilling conditions prior to surface casing being set, the permit holder may request an amendment of the permit without a fee for the new location, provided the production well remains on the same surface owners’ property where the production well was originally permitted.

(B) The Director of Production and Conservation may approve the commencement of drilling operations prior to the filing of an amended permit.

(C) Movement of the production well location off the original surface owners’ property, or after surface casing has been set, requires the filing of a new permit application, along with a new permit fee and plat.

(D) Drilling may not commence prior to the issuance of a new permit.

(5)(A) Application for a permit to drill, deepen, or reenter a plugged production well shall be made on forms prescribed by the director.

(B)(i) The application shall be executed under penalties of perjury accompanied by a nonrefundable permit fee of three hundred dollars ($300).

(ii) The permit shall not be issued until any required financial assurance in accordance with 15 CAR § 275-202 is submitted and approved.

(6)(A) If the application does not contain all of the required information or required documents, the director or his or her designee shall notify the applicant in writing.

(B) The notification shall:

(i) Specify the additional information or documents necessary for an evaluation of the application; and

(ii) Advise the applicant that the application will be deemed denied unless the information or documents are received within sixty (60) days following the date of mailing or personal delivery of the notification.

(7) Permits shall automatically expire six (6) months from the date of issuance, unless commencement of the drilling, deepening, or reentry of plugged production well operations authorized by the permit has occurred, which are to be continued with due diligence, but not to exceed one (1) year from the date of commencement of the drilling, deepening, or reentry of plugged production well operations authorized by the permit, at which time the production well shall be plugged or a new permit application, along with a new permit fee and plat, must be filed.

(8)(A) Permits for the drilling, deepening, or reentry of a plugged production well are not transferable prior to the completion of drilling operations and the setting of surface casing.

(B) A new permit application, along with a new permit fee and plat must be filed.

(9) The permit application to drill, deepen, or reenter a plugged production well shall include at a minimum:

(A) The proposed name of the production well;

(B)(i) The surveyed location and ground elevation of the production well.

(ii) A survey is not required for a deepened production well or a reentered plugged production well if the original production well location was surveyed and shown on the original production well permit application.

(iii) If the application is for a horizontal production well, the surface location and proposed bottom hole location of the lateral portion of the horizontal production well shall be shown.

(iv) If applicable, a Form 25 must be submitted for horizontal production wells where the costs and production are to be shared between drilling units in accordance with 15 CAR § 275-230 or 15 CAR § 275-231, or a Form 5 must be submitted for a location exception in accordance with 15 CAR § 275-227;

(i) The exact location of the production well proposed to be drilled, deepened, or reentered;

(ii) An outline of the proposed drilling unit and/or leasehold, whichever is applicable, unless the production well is a wildcat well;

(iii) The distance from the production well to the nearest section lines, drilling unit lines, and/or lease lines, whichever is applicable; and

(iv) If the production well is located within a controlled oil or gas field, the plat shall also include the location of all producing wells completed or producing within the same common source of supply in the drilling unit and/or leasehold;

(D) The name of the proposed drilling contractor;

(E) The proposed depth of the production well; and

(F) The name of the deepest geologic formation to be tested.

(10) The application for a permit to drill, deepen, or reenter a plugged production well shall be signed by a person authorized to sign for such owner as specified on the organizational report filed in accordance with 15 CAR § 275-212.

(11) The applicant must be authorized to do business in the State or Arkansas, and by filing an application, the applicant irrevocably waives, to the fullest extent permitted by law, any objection to a hearing before the commission.

(12) If the applicant satisfies the requirements of all applicable statutes and this section, a permit shall be issued, and in no circumstances be unduly withheld, unless:

(A) The applicant has falsified or otherwise misstated any material information on or relative to the permit application; or

(B) No further permits or authorities may be issued in accordance with 15 CAR § 275-104.

(1) The director may revoke a production well drilling permit if the:

(A) Permit holder fails to meet permit conditions as specified in the production well drilling permit;

(B) Production well permit was issued in error; or

(2)(A) The director shall notify the permit holder of the production well drilling permit in writing.

(B) Following the revocation notice, the permit holder is required to plug the production well.

(C)(i) The permit holder shall have thirty (30) days from the date of the production well drilling permit to appeal the director’s decision to revoke the production well drilling permit in accordance with 15 CAR §§ 275-101 and 275-102, and other applicable hearing procedures.

(ii) Drilling or production may not commence or continue during the appeal process.

(D) A revocation of a production well drilling permit for which an appeal has not been filed shall become a final administrative decision of the commission thirty (30) days following the date of the revocation.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book; amended July 29, 2011; amended January 20, 2014)" Authorities: Arkansas Code § 15-71-110; Arkansas Code § 15-72-205

15 CAR § 275-202 Proof of financial responsibility required to be furnished {#sec-15-car-275-202 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-202}

15 CAR § 275-202. Proof of financial responsibility required to be furnished.

(a) For purposes of this section, the person, operator, producer, or owner designated by the Director of Production and Conservation or his or her designee as the party responsible for compliance, and whom is the entity required to hold the permit to drill, produce, dispose, or inject, will be referred to as the permit holder.

(b) Financial assurance is required to be submitted with the following applications:

(1) An application to drill:

(A) An oil and/or gas well;

(B) Class II disposal well;

(D) Brine production well;

(E) Class V brine disposal well;

(F) Water supply well; or

(G) Other type of exploratory hole or holes or well or wells; or

(2) An application to transfer ownership or operations of any existing oil and/or gas well, Class II disposal well, injection well, brine production well, Class V brine disposal well, water supply well, or other type of exploratory hole or holes or well or wells to another permit holder.

(1) For a minimum of one (1) year after the issuance of the permit to drill in accordance with Arkansas Code § 15-72-214 if the well is not drilled;

(2) If the well is drilled, until the well or wells have been plugged and associated production site or sites restored in accordance with Oil and Gas Commission rules; or

(3) Until the well or wells have been transferred to a new permit holder in accordance with commission rules.

(d) Financial assurance no longer required to remain in full force and effect in accordance with subsection (c) of this section shall only be released, if at the time of request to release, the following conditions have been satisfied:

(1) All outstanding notices of violation or orders of compliance issued against the permit holder have been satisfied;

(2) If applicable, the permit holder has paid annual fee assessments to the commission in accordance with subsection (h) of this section for two (2) consecutive years; and

(3) All permit holders of record with the commission on January 1, 2006, who were:

(A) Assessed annual fees in accordance with subsection (h) of this section and paid such fees; and

(B) Not in violation of any commission order or rule at the time the fees were paid.

(e) Financial assurance shall be submitted and payable to the commission in the form of:

(1) A surety bond issued by a surety company authorized to transact business in Arkansas; or

(2) An irrevocable letter of credit subject to the following conditions:

(A) The letter of credit shall be issued by a bank whose deposits are insured by the Federal Deposit Insurance Corporation; and

(B)(i) The letter of credit shall provide on its face that the commission, its lawful assigns, or the attorneys for the commission or its assigns, may sue, waive notice and process, appear on behalf of, and confess judgment against the issuing bank and any confirming bank in the event that the letter of credit is dishonored.

(ii) The letter of credit shall be deemed to be made in Union County, Arkansas, for the purpose of enforcement and any actions thereon shall be:

(a) Enforceable in the courts of Arkansas; and

(b) Construed under Arkansas law;

(3) A certificate of deposit subject to the following conditions:

(A)(i) The director or his or her designee shall require that certificate of deposit be made payable to or assigned to the commission both in writing and upon the records of the bank issuing the certificate.

(ii) If assigned, the director or his or her designee shall require the banks issuing these certificates to waive the rights of setoff or liens against those certificates;

(B) The director or his or her designee shall not accept an individual certificate of deposit in an amount in excess of the maximum insurable amount as determined by the Federal Deposit Insurance Corporation or the Federal Savings and Loan Insurance Corporation;

(C) Any interest accruing on a certificate of deposit shall be for the benefit of the permit holder except that accrued interest shall first be applied to any prepayment penalty when a certificate of deposit is forfeited by the commission; and

(D)(i) The certificate of deposit, if a negotiable instrument, shall be placed in the commission’s possession.

(ii) If the certificate of deposit is not a negotiable instrument, a withdrawal receipt, endorsed by the permit holder, shall be placed in the commission’s possession.

(4) Cash submitted in the form of personal or corporate check, money order, or cashier’s check to be deposited in the commission’s authorized bank account.

(f) Financial assurance shall be required for all:

(1) Holders of permits to drill and/or operate gas wells and all Class II disposal wells injecting fluids associated with dry gas production wells;

(2) Permit holders of commercial Class II disposal wells;

(3) Permit holders of brine production and Class V brine disposal well or wells;

(4) Permit holders of other types of wells or exploratory holes or wells; and

(5) Permit holders of liquid hydrocarbons production wells and Class II disposal and enhanced oil recovery injection wells operated in conjunction with liquid hydrocarbon wells, that have not been a permit holder of record with the commission for a minimum of two (2) calendar years preceding the date of the application specified in subsection (b) of this section, above.

(g)(1) When a permit holder is required to submit financial assurance, the minimum amount of the financial assurance shall be:

(A) Three thousand dollars ($3,000) per well for an oil or gas production well, Class II UIC SWD well associated with liquid hydrocarbon wells, Class II UIC enhanced recovery well or water supply well used in connection with an enhanced oil recovery project, or a blanket financial assurance for oil or gas production, Class II enhanced recovery, and water supply wells as follows:

(i) Twenty-five thousand dollars ($25,000) for one to twenty-five (1 – 25) wells;

(ii) Fifty thousand dollars ($50,000) for twenty-six to one hundred (26 – 100) wells; or

(iii) One hundred thousand dollars ($100,000) for one hundred one (101) or more wells;

(B) Twenty-five thousand dollars ($25,000) per well for a brine production or blanket financial assurance for brine production or supply wells as follows:

(i) Two hundred fifty thousand dollars ($250,000) for one to twenty-five (1 – 25) wells;

(ii) Five hundred thousand dollars ($500,000) for twenty-six to fifty (26 – 50) wells; or

(iii) One million dollars ($1,000,000) for fifty-one (51) or more wells;

(C) Twenty-five thousand dollars ($25,000) per well for a Class II disposal not associated with liquid hydrocarbon wells or Class V brine injection wells; and

(D) Fifty thousand dollars ($50,000) per well for a Class II commercial disposal well, plus an additional financial assurance for the associated surface facilities as follows:

(i) Fifty thousand dollars ($50,000) for one thousand (1,000) bbls of on-site tank storage;

(ii) One hundred thousand dollars ($100,000) for over one thousand (1,000) up to two thousand (2,000) bbls of on-site tank storage; or

(iii) Two hundred fifty thousand dollars ($250,000) for over two thousand (2,000) bbls of on-site tank storage; plus

(iv) an additional one hundred fifty thousand dollars ($150,000) if a sump or dump vat is utilized at the site to off-load fluids.

(2)(A) The director or his or her designee is authorized to approve administratively each financial assurance instrument required to be filed with the commission.

(B) The director is further authorized to require additional financial assurance based on but not limited to:

(i) How long a permit holder has operated in the state;

(ii) Environmental consideration of the well location or surface storage facilities, and other environmental, engineering, or geological factors impacting the cost of plugging the well and restoring the associated well site or storage facility; and

(iii) The compliance history of the permit holder.

(h) Effective January 1, 2006, financial assurance in the form of annual fees shall be paid by all permit holders of liquid hydrocarbon wells and any Class II disposal or Class II enhanced recovery wells associated with liquid hydrocarbon wells, as follows:

(1) Fees shall be assessed annually for all issued permits and wells of record as of January 1 of each year;

(2) All assessed fees shall be paid in full by March 1 of each year, after which time the permit holder’s authority to produce and transport and authority to dispose and/or inject will be terminated until all delinquent fees are paid;

(3)(A) The permit holder shall remain liable for the payment of such fees until the well or wells under permit to the permit holder are plugged and restored, or the well or wells have been transferred to a new permit holder pursuant to commission rules.

(B) Liability for payment of annual well fees ceases on the:

(i) Date when the well has been plugged and restored; or

(ii) Effective date stated on the commission’s Notification of Transfer form; and

(4) If a permit holder’s fee check is returned due to insufficient funds or because payment was stopped, the permit holder is required to repay fees for that year by cashier’s check or money order.

(i)(1) A permit holder may administratively contest the amount of the fee assessment by submitting a written objection to the assessment amount on or before March 1 of each year.

(2) The objection must:

(A) Be accompanied by the full assessed amount;

(B) Be in writing;

(D) Identify the nature of the objection; and

(E) Include a statement of the facts supporting the objection and copies of any relevant documents to support the objection.

(3) The director or his or her designee shall:

(A) Review the application; and

(B) Have the authority to amend the fee assessment and refund any monies due the permit holder.

(j) The amount of annual fees assessed each January 1 to all permit holders of liquid hydrocarbon and associated Class II wells shall be as follows:

(1) One (1) to five (5) permits or wells, one hundred dollars ($100) per well;

(2) Six (6) to fifteen (15) permits or wells, seven hundred fifty dollars ($750) per operator;

(3) Sixteen (16) to fifty (50) permits or wells, one thousand two hundred fifty dollars ($1,250) per operator;

(4) Fifty-one (51) to one hundred fifty (150) permits or wells, two thousand dollars ($2,000) per operator;

(5) One hundred fifty-one to three hundred permits or wells, three thousand dollars ($3,000) per operator; or

(6) Three hundred one or more permits or wells, four thousand dollars ($4,000) per operator.

(k) Permit holder’s failure to comply with the commission’s order to plug, replug, or repair a well, or to restore a well site within thirty (30) days of the issuance of such order constitutes grounds for forfeiture of the financial assurance held by the commission, as follows.

(1) The director shall send written notification by certified mail, return receipt requested, to the permit holder and the issuer of the financial assurance, if any, informing them of the director’s determination to forfeit the financial assurance for failure to comply with the above commission order.

(2)(A) The director may allow the financial assurance issuer to undertake necessary plugging, replugging, repair, or site restoration work if the financial assurance issuer can demonstrate an ability to complete such work in accordance with commission rules.

(B) No financial assurance liability shall be released until the successful completion of all plugging, replugging, repair, or site restoration ordered by the commission.

(3)(A) In the event forfeiture of the financial assurance is warranted under the provisions of this section, the director shall afford the permit holder the right to a hearing, if such hearing is requested in writing by the permit holder within fifteen (15) days after the forfeiture notification is mailed in accordance with subdivision (k)(1) of this section.

(B) If the permit holder does not request a hearing within the fifteen-day period, the director shall issue a final decision ordering forfeiture and collection of funds.

(C) If a hearing is requested by the permit holder, the hearing shall be docketed for the next regularly scheduled commission hearing.

(4)(A) At the forfeiture hearing, the director shall present evidence in support of the determination for financial assurance forfeiture.

(B) The permit holder shall present evidence contesting the director’s determination.

(C) The commission may administer oaths and affirmations, subpoena witnesses and written or printed materials, compel attendance of witnesses or production of those materials, compel discovery, and take evidence necessary to render a decision.

(5) Within thirty (30) days after the close of the record for the forfeiture hearing, the commission shall issue:

(A) Findings of fact;

(B) Conclusions of law; and

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book; amended (Order 27-95) June 20, 1995; amended (Order 4-99) March 23, 1999; amended January 15, 2006; amended October 15, 2006; amended November 16, 2008; amended June 5, 2009; amended November 28, 2024)" Authorities: Arkansas Code § 15-71-110; Arkansas Code § 15-71-116

15 CAR § 275-203 Spacing of wells {#sec-15-car-275-203 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-203}

15 CAR § 275-203. Spacing of wells.

(a) For purposes of this section and with respect to all established field rules, exploratory drilling units, wildcat wells, and in uncontrolled areas, the term “well location” shall be defined as follows:

(1)(A) For the purpose of well drilling permit issuance, “well location” is defined as the proposed bottom hole location in a vertical or directionally drilled well or the estimated productive portion of a lateral in a horizontal well, projected to the surface.

(B) For purposes of assigning an API number, the well site location shall be considered the actual surface location of the well; and

(2) For the purpose of well setback provisions, except in uncontrolled areas, well location is defined as the actual physical location of the completed interval in the well, projected to the surface, as follows:

(A)(i) In a vertically drilled well without a directional survey, the well location is the surface location.

(ii) In a vertically drilled well, the well location is the location of the perforated interval of the well bore, projected vertically to the surface;

(B) In a directionally drilled well, the well location is the location of the midpoint of the perforated interval of the producing formation, as calculated from the directional survey, projected vertically to the surface; or

(C) In a horizontally drilled well, the well location is the entire perforated length of the lateral section of the well bore, as shown on a directional survey, projected vertically to the surface.

(b) The spacing of wells in oil and gas fields established by Oil and Gas Commission order, shall be governed by field rules for that particular field, adopted after notice and hearing.

(c) The spacing of wells in other areas designated as prospective of oil and gas production shall be governed by general rule adopted after notice and hearing.

(d) The well location for a well drilled for oil or gas production in an exploratory drilling unit established by commission order shall not be located closer than two hundred eighty feet (280’) from the drilling unit boundary, except that wells drilled in exploratory drilling units established by 15 CAR § 275-230 or 15 CAR § 275-231, shall be governed by the applicable well setback provisions of 15 CAR § 275-230 or 15 CAR § 275-231, respectively.

(e) The following applies to all wildcat well locations not drilled in exploratory drilling units:

(1) The well location for a wildcat well drilled for oil or gas production purposes, within an area not covered by field rules, 15 CAR § 275-230 or 15 CAR § 275-231, shall not be located closer than two hundred eighty feet (280’) from a quarter, quarter division line within a governmental section; and

(2) The well location for a wildcat well, drilled for the purposes of oil or gas production, within an area subject to field rules, but proposed to be drilled to a geologic formation for which field rules have not been established, shall be subject to the setback provisions specified in subdivision (e)(1) of this section, above.

(f) The well location for a well drilled for oil or gas production purposes, and completed in pools in fields where field rules do not exist for these uncontrolled pools, shall not be located closer than two hundred eighty feet (280’) from the nearest mineral lease line.

(g) The following applies to injection wells drilled or completed for enhanced recovery, Class II disposal wells, or Class II commercial disposal wells, as defined by 15 CAR § 275-801:

(1) The well location for an injection well drilled or completed for enhanced recovery purposes shall not be located closer than two hundred eighty feet (280’) from a unitized boundary line;

(2) The well location for a Class II disposal well or Class II commercial disposal well, drilled or completed pursuant to 15 CAR § 275-801, shall be located no closer than two hundred eighty feet (280’) from the drilling unit boundary in controlled fields;

(3) The well location for a Class II disposal well or Class II commercial disposal well, drilled or completed pursuant to 15 CAR § 275-801, outside of a controlled field and not within an uncontrolled field, shall be located no closer than two hundred eighty feet (280’) from a quarter, quarter division line within a governmental section; and

(4)(A) The well location for a Class II disposal well or Class II commercial disposal well, within an uncontrolled field, drilled or completed pursuant to 15 CAR § 275-801, shall be located no closer than two hundred eighty feet (280’) from the mineral lease line.

(B) However, with regards to Class II disposal wells, this requirement may be waived by the Director of Production and Conservation if the offset operator which is being encroached upon gives written permission for the Class II disposal well to be located at a closer distance and waives the requirement of a hearing before the commission to the operator of the Class II disposal well and the appropriate commission regional office.

(h)(1) The well location for wells drilled for the purposes of water supply for purposes of enhanced oil recovery are subject to all the provisions of this section with the exception of the setback provisions for well location.

(2) No production of hydrocarbons will be allowed from a water supply well.

(i)(1) The commission may, after notice and hearing, grant exceptions to this section, provided such exceptions will create neither waste nor hazards conducive to waste.

(2) No well drilled in violation of this section without special permit obtained in the manner prescribed in said rule and no well drilled under such a special permit, which does not conform to the terms of such special permit in all respects, shall be permitted to produce either oil or gas and any such well so drilled in violation of said rule or in violation of a permit granted under an exception to this section shall be plugged.

History

Codification Notes: “API” means American Petroleum Institute.This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book; amended November 13, 2005; amended September 16, 2006; amended November 19, 2018)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-204 Application to transfer a well {#sec-15-car-275-204 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-204}

15 CAR § 275-204. Application to transfer a well.

(a) Definitions. As used in this section:

(1) "Current permit holder" means the person required to hold the permit or to whom the permit was issued and who:

(A) Is the owner of the right to drill, produce, and/or operate said well or wells;

(B) Possesses the full rights and responsibilities for operating the well or wells in accordance with applicable Arkansas law and/or rule or order of the Oil and Gas Commission; and

(C) Has the current obligation to plug said well or wells, and who is the assignor, transferor, or seller, whether voluntary or involuntary, of the well or wells;

(2)(A) “Deepen” for a cased well means an operation whereby a well is drilled to a measured depth below the cement casing shoe.

(B) For an open hole completion, “deepen” means an operation whereby a well is drilled below the original measured depth of the well;

(3) “Drill” means the commencement of an operation to either set conductor pipe or the moving in a drilling rig capable of drilling to a depth to set the requisite amount of surface casing and spudding the well, if conductor pipe is not used;

(4) "New permit holder" means the person acquiring the well or wells and the right to drill, produce, and/or operate said well or wells, who:

(A) Obtains the full rights and responsibilities for operating the well or wells in accordance with applicable Arkansas law and/or rule or order of the Oil and Gas Commission;

(B) Will obtain the obligation to plug said well or wells; and

(C) As owner or operator in accordance with applicable Arkansas law and/or rule or order of the Oil and Gas Commission, is required to hold the permit;

(5) “Reenter” means an operation whereby surface access to the wellbore is established;

(6) “Transfer” means any assignment, devise, release, transfer, takeover, buyout, merger, sale, conveyance, or other transfer of any kind, whether voluntarily or involuntarily; and

(7) “Well” means a production well as defined by 15 CAR § 275-201.

(b) The provisions of this section apply to all transfers of the interest of the person required to hold and to whom the well transfer approval is issued (permit holder), including but not limited to a change:

(1) Of ownership of the right to drill, produce, and/or operate well or wells, including the obligation to ultimately plug said well or wells;

(2) In the designation of the owner or operator under an operating or other similar agreement;

(3) Pursuant to the action of the owners of separate interests who designate an owner to be permit holder; or

(4) Required by the appointment, by a court of competent jurisdiction, of a trustee or a receiver to exercise custody and control over the well or wells, including the right to drill, produce, and/or operate well or wells, and the obligation to ultimately plug said well or wells.

(c) The provisions of this section shall not apply to the transfer of the royalty, overriding royalty, or fractional working interests not affecting the rights or responsibilities of the permit holder.

(d)(1) The provisions of this section shall not apply to transfers of a well or wells abandoned or orphaned in accordance with 15 CAR § 275-701 or 15 CAR § 275-702.

(2) Transfers of a well deemed abandoned or orphaned are subject to the transfer provisions in 15 CAR § 275-703.

(e) Notification of a transfer shall be given to the Director of Production and Conservation or his or her designee by the current permit holder on a form prescribed by the director.

(f) A separate form shall be completed for each lease, well, or other unit transferred.

(g) The notification shall be signed by the current permit holder and the new permit holder, or by authorized representatives specified on the organizational report filed in accordance with 15 CAR § 275-212, except as follows:

(1) In lieu of the signature of the current permit holder, the new permit holder may submit a court order or other legal document evidencing ownership of the lease or unit to be transferred in the event that the current permit holder cannot be located or refuses to sign the notification of transfer form; or

(2) In lieu of the signature of the new permit holder, the current permit holder may submit documentation evidencing transfer of the ownership of the well, lease, or unit in the event the new permit holder refuses to sign the notification of transfer form.

(h) Prior to the director or his or her designee approving the transfer request, the new permit holder shall:

(1) Be authorized to do business within the State of Arkansas;

(2) Provide the required financial assurance, if applicable, in accordance with 15 CAR § 275-202 and subdivisions (h)(4) and (5) of this section, below;

(3) File the required organizational report, if applicable, in accordance with 15 CAR § 275-212; and

(4)(A)(i) If the transfer is for a gas well producing less than twenty-five (25) Mcf/day per Oil and Gas Commission records, or a well that has received an approved temporary abandonment status in accordance with 15 CAR § 275-207, then the current permit holder and new permit holder may file an application, on a form prescribed by the director, requesting administrative approval of the transfer request.

(ii) If the transfer request is approved administratively, the permit holder shall file an additional, well-specific financial assurance of thirty-five thousand dollars ($35,000) for each natural gas well in a form authorized by 15 CAR § 275-202.

(iii)(a) If the transfer request is denied, or if the director notifies the current permit holder and the new permit holder that he or she is referring the request to the commission, the current permit holder and new permit holder may file an application in accordance with 15 CAR §§ 275-101 and 275-102, and other established hearing procedures to have the commission review the transfer request.

(b) If the transfer request is approved by the commission after notice and hearing as provided above, the new permit holder shall file an additional, well-specific financial assurance of thirty-five thousand dollars ($35,000) for each natural gas well in a form authorized 15 CAR § 275-202, unless otherwise provided by the commission after notice and hearing.

(B) If the transfer for a liquid hydrocarbon production well has received an approved temporary abandonment status in accordance with 15 CAR § 275-207, then the new permit holder is required to replace any amount of well-specific financial assurance that is required by the current permit holder, unless otherwise provided by the commission after notice and hearing, prior to transfer.

(i) A transfer to a new permit holder shall be denied by the director or his or designee if:

(1) The new permit holder has not fully satisfied all applicable requirements;

(2) The commission has not approved the transfer in accordance with subdivision (h)(4)(A) of this section, above;

(3) The new permit holder has falsified or otherwise misstated any material information on or relative to the transfer application;

(4) No further permits or authorities may be issued in accordance with 15 CAR 275-104(e)(12); or

(5) The director or his or her designee deems it necessary that the transfer request be denied:

(A) For the purpose of protecting correlative rights of all parties; or

(B) To prevent waste as defined by Arkansas Code § 15-72-102.

(j)(1) The new permit holder shall be responsible for all regulatory requirements relative to all wells and all other surface facilities in existence at the time of the transfer related to the wells.

(2) The new permit holder shall not be responsible for regulatory requirements relative to spills of crude oil or other production fluids which occurred prior to the date of the transfer, unless the new permit holder has otherwise agreed with the current permit holder.

(k)(1) If any well, or any lease or other unit associated with the well, is in violation at the time of the transfer request to the new permit holder, the transfer request shall be denied pending abatement of all violations by the current permit holder.

(2) However, if the new permit holder, after being notified of the violation or violations, agrees in writing to the transfer approval including conditions to abate all violations, the transfer may be approved by the director or his or her designee in accordance with this section.

(3) Failure to abate the violations within the time period specified by the director or his or her designee may result in revocation of the transfer approval in accordance with subsection (o) of this section, below, and/or other applicable enforcement actions in accordance with 15 CAR § 275-104.

(l)(1) The current permit holder is not responsible for any regulatory violation caused by the actions of the new permit holder during the permit transfer process.

(2) However, if the transfer is denied by the director or his or her designee, the current permit holder assumes all responsibility for the violations caused by the new permit holder.

(3) Nothing in this subsection shall affect the contractual rights and obligations between the person or entity transferring the well or wells and the person or entity acquiring the well or wells.

(m) The transfer request shall not affect the rights of the commission, or any obligation or duty of the current permit holder arising under any applicable Arkansas laws, or rules, or orders of the commission.

(n)(1) The director shall notify the current and new permit holder of the transfer approval or denial in writing.

(2) Following the approval or denial of the transfer approval request, the current or new permit holder shall have thirty (30) days from the date of the approval or denial to appeal the director’s decision in accordance with 15 CAR §§ 275-101 and 275-102 and other applicable hearing procedures.

(3) A transfer request approval or denial, for which an appeal has not been filed, shall become a final administrative decision of the commission thirty (30) days following the date of the approval or denial.

(o) Well transfer revocation procedures.

(1) The director may revoke a well transfer approval if the:

(A) Permit holder fails to meet permit conditions as specified in the well transfer approval;

(B) Well transfer approval was issued in error; or

(2)(A) The director shall notify the permit holder of the well transfer revocation in writing.

(B) Following the revocation notice, the permit holder is required to plug the well.

(C) The permit holder shall have thirty (30) days from the date of the well transfer revocation to appeal the director’s decision to revoke the well transfer approval in accordance with 15 CAR §§ 275-101 and 275-102 and other applicable hearing procedures.

(D) Drilling, production, or operation may not commence or continue during the appeal process.

(E) A revocation of a well transfer approval for which an appeal has not been filed shall become a final administrative decision of the commission thirty (30) days following the date of the revocation.

History

Codification Notes: “Mcf” means one thousand cubic feet (1,000 ft3).This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Rule Repealed Effective November 11, 2007; New Rule Effective November 19, 2018, amended May 08, 2022)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-205 Submission of well records and issuance of certificate of compliance {#sec-15-car-275-205 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-205}

15 CAR § 275-205. Submission of well records and issuance of certificate of compliance.

(a) During the drilling, original completion, recompletion, or workover of every well, the owner, operator, contractor, driller, or other person responsible for the conduct of drilling, original completion, recompletion, or workover operations, shall keep adequate records of the well being drilled, all of which shall be accessible to the Oil and Gas Commission and its agents at all reasonable times.

(b)(1) For purposes of this section, original completion shall be defined as initial zone perforation and configuration of wellhead for production, excluding pipeline connections.

(2) Any further completion work, after the initial configuration of the wellhead, shall be considered a recompletion or workover, and subject to the filing requirements of subsections (d) or (f) of this section, below.

(d)(1) For purposes of this section, “workover” is as defined in 15 CAR § 275-103.

(2) Upon completion of workover operations, only well records specified in subdivisions (f)(1) – (3) of this section are required to be submitted.

(e) Wells drilled as dry holes, where production casing has not been set, shall be subject to the well record submission requirements specified in subdivisions (f)(1) – (3) of this section within thirty (30) days after the completion of drilling activities.

(f) Upon original completion or recompletion of the well, the operator, contractor, driller, or other person responsible for the conduct of the drilling operation shall file with the commission:

(1) Properly filled out Well Completion Report;

(2)(A) All electric logs or other geophysical logs of the open well bore, which measure resistivity, porosity, temperature, and gamma ray emission and for planned directional and horizontal wells, borehole deviation, and direction logs including a true vertical depth log, to be submitted in:

(i) A one-inch, two-inch, and five-inch to one hundred foot (100’) scale format; or

(ii) Other scale format acceptable to the commission.

(B) All logs shall be submitted, at a minimum, as paper copies in standard continuous logging paper format.

(C)(i) If electronic copies of the logs can be provided from the logging service company, the operator is also required to submit copies of the electronic logs in either LAS (ASCII Format) or raster format image (two hundred dots per inch (200 DPI) black and white in TIF, JPG, BMP) to the commission on an approved electronic storage device.

(ii) If electronic copies of the logs cannot be provided by the logging service company, the operator shall file an affidavit with the commission stating electronic logs could not be provided by the logging service company;

(3) All logging and well service company tickets applicable to the completion or recompletion operation which indicate all logging and completion activities occurring in the well;

(4) Properly filled out Request for Certificate of Compliance; and

(5) Application to Abandon other than for a dry hole.

(g) For directional or horizontal wells, or deviated wells not in compliance with 15 CAR § 275-220, the following shall also be submitted:

(1)(A) A post drilling plat shall be filed with any Completion and Recompletion Report to demonstrate the actual location of all vertical, directional, and horizontally drilled boreholes in the drilling unit.

(B) The plat should provide and present the following:

(i) The locations of all wells which have been drilled within the drilling unit, except for those wells that have been plugged and abandoned, by providing their surface and bottom hole location, and either midpoint perforations for deviated or directionally drilled wells or the closest point along any lateral section of the horizontal portion of the well bore, whichever is applicable, measured to the nearest mineral lease, drilling unit, or division line within a governmental section, whichever applies to the established drilling unit in that field;

(ii) The distance between common sources of supply for which an allowable determination is required; and

(iii) The actual location of the entire perforated length of the lateral section in a horizontal well showing the setback distances to offset wells; and

(2) A directional survey in table form, accompanied by the following:

(A) A two-dimensional cross section diagram, viewed perpendicular to the axis of maximum lateral borehole displacement, which depicts the measured and true vertical depth and the displacement from vertical of the wellbore; and

(B) An azimuth plot viewed in plan view providing displacement of the well path from the surface location.

(h)(1) The above reports shall be filed within thirty (30) days of the original completion, recompletion, or workover of the well and prior to commencement of production.

(2) Upon receipt of the required information specified in subdivisions (f)(1), (2), and (4) of this section and 15 CAR § 275-230(o)(3)(J), if applicable, a Certificate of Compliance shall be issued granting authority to produce and transport oil and/or gas for a period of thirty (30) days at which time the required information specified in subdivision (f)(3) of this section must be on file in order for a final Permit to Produce and Transport to be issued.

(3) However, if completion activities are not completed within ninety (90) days of the setting of the production casing or other production-related casing, the required information specified in subdivisions (f)(1) – (3) of this section are required to be submitted, pending submission of final reports at the conclusion of completion activities and a request for a Certificate of Compliance.

(i) Failure to comply with the provisions of this section shall be sufficient reason to cause the suspension of the issuance of any further drilling permits on a statewide basis to that operator until the required information is submitted to the commission within ten (10) days following written notice provided to the operator of the failure to provide the required information.

(j) If an operator makes a request, in writing, that the log described in subdivision (f)(2) of this section be kept confidential, the request will be honored for a period not to exceed ninety (90) days after the logging for completion or abandonment of the well, provided that the report or the data thereon, when pertinent, may be introduced in evidence in any public hearing before the commission or any court, regardless of the request that such record be kept confidential.

History

Codification Notes: “BMP” means bitmap."TIF" means tagged image format.This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book; amended September 16, 2006; amended January 14, 2008; amended May 11, 2008)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-206 Oil, gas, and water to be protected {#sec-15-car-275-206 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-206}

15 CAR § 275-206. Oil, gas, and water to be protected.

Before any well or any producing horizon encountered therein shall be abandoned, the owner or operator shall use such means, methods, and procedures as may be necessary to:

(1) Prevent water from entering any oil or gas-bearing formations; and

(2) Protect any underground or surface water that is suitable for domestic or irrigation purposes from:

(A) Waste;

(B) Downward drainage;

(D) The addition of deleterious substances.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-207 When wells shall be plugged and abandoned and notice of intention to plug and abandon wells {#sec-15-car-275-207 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-207}

15 CAR § 275-207. When wells shall be plugged and abandoned and notice of intention to plug and abandon wells.

(a)(1) The current permit holder is responsible for plugging wells as defined in this section.

(2) In the case of leaking wells, plugging responsibility is in accordance with 15 CAR § 275-219(k) and (l).

(b) All new wells drilled for liquid hydrocarbons, natural gas, or brine exploration, or brine production, water supply, or injection purposes, except such holes as are described in 15 CAR § 275-210, regardless of depth, are required to be either properly cased with production casing or the uncased well or dry hole shall be plugged and abandoned in accordance with applicable Oil and Gas Commission rules, unless an extension of time to plug is granted in accordance with subsection (c) of this section, below.

(1)(A) Any well in which production casing is not set and cemented shall be plugged in accordance with applicable commission rules, prior to the time that the equipment used to drill said well is released from the drilling operation.

(B) In the case of staged drilling operations, where multiple drilling rigs are used to drill the well over a period of time, production casing shall be set and cemented within one hundred eighty (180) days after setting of the surface casing or the well shall be plugged, unless an extension of time to plug is granted in accordance with subdivision (c)(2) of this section, below.

(2)(A) The Director of Production and Conservation, however, may grant an extension of time to plug an uncased well.

(B) In determining whether to grant an extension and in determining the length of an extension, the director may consider:

(i) The permit holder’s specific plans for further wellbore utilization;

(ii) The total depth of the well;

(iii) The depth of surface and any intermediate casing;

(iv) A description of the current condition of the hole including a description of the type of drilling fluids currently in the well; and

(v) The location of the well.

(3) If the director determines that the uncased well presents a risk of contamination to the environment or a risk to public safety, the permit holder shall be required to repair, case, plug, or perform other remediation measures to the well, as determined by the director, within twenty-four (24) hours after notification by the director.

(d)(1) All cased wells utilized for liquid hydrocarbons, natural gas or brine production, water supply or injection purposes, except such holes as are described in 15 CAR § 275-210, or liquid hydrocarbon production wells located on actively producing leases, shall be plugged and abandoned in accordance with applicable commission rules after the well has been idle for more than twenty-four (24) months, or sooner, should the director determine that the cased well presents a risk of contamination to the environment or a risk to public safety, unless an application is filed to request temporary abandonment status for the well in accordance with subsection (h) of this section, below.

(2)(A) Upon such determination by the director or if temporary abandonment status is denied, the permit holder shall commence plugging the well within thirty (30) days after notification by the director.

(B) Failure to commence plugging the well within thirty (30) days after notification by the director may result in the initiation of well abandonment proceedings in accordance with 15 CAR § 275-701.

(e) Prior to the commencement of any work in plugging and abandonment operations, the permit holder or other person responsible for the conduct of the drilling operations shall give notice of the intent to plug and abandon such well in a form prescribed by the director as follows:

(1) For uncased wells and dry holes, notice shall be provided via verbal or facsimile communication to the commission regional office where the well is located, as soon as possible, but no less than eight (8) hours prior to commencement of plugging operations; or

(2) For cased wells, written notice on a form prescribed by the director shall be provided to the commission regional office where the well is located at least seventy-two (72) hours prior to the commencement of plugging operations.

(f) Upon receipt and review of such verbal or written notice, the commission regional office:

(1) Shall authorize the commencement of plugging operations; and

(2) May send a duly authorized commission representative to the well location to witness the plugging of such well.

(g)(1) Authorization to plug and abandon is not granted unless the appropriate notice, as specified in subsection (e) of this section, above, has been provided to the commission by the permit holder or person responsible for the plugging of the well.

(2) Plugging of the well without providing proper notice as required can result in the permit holder being required to drill out the well plugs and the well replugged under commission observation.

(h) Temporary abandonment status.

(1)(A) An application for temporary abandonment status shall be made on a form prescribed by the director and, if approved, shall be valid for a period not to exceed three (3) years from the date of the director’s approval.

(B) At the expiration of the three-year period, the permit holder shall:

(i) Commence plugging operations within thirty (30) days; or

(ii) File an application to request a hearing before the commission in accordance with 15 CAR §§ 275-101 and 275-102 and other applicable hearing procedures to request an extension of the three-year period of the temporary abandonment status.

(C) Wells in an approved waterflood/enhanced oil recovery unit are exempt from the initial three-year time limit as long as the unit remains active.

(2)(A) Wells which have not produced for more than ten (10) years are not eligible for approval by the director of temporary abandonment status, unless the well is in an approved waterflood/enhanced oil recovery unit that remains active.

(B) Temporary abandonment status for these wells may only be granted by the commission after notice and a hearing in accordance with 15 CAR §§ 275-101 and 275-102 and other applicable hearing procedures.

(3) Temporary abandonment status shall be approved by the director, provided that:

(A)(i) Financial assurance in the amount of thirty-five thousand dollars ($35,000) per well for any dry natural gas production well, or fifteen thousand dollars ($15,000) per well for any liquid hydrocarbon production well, is submitted for each well.

(ii) The financial assurance shall:

(a) Be in a form as prescribed by 15 CAR § 275-202; and

(b) Remain valid until the well is put back into sustained production, plugged, or transferred;

(B) The well is secured with a suitable wellhead with no leakage of any substance at the surface;

(D) Proper well identification is maintained in accordance with 15 CAR § 275-219(b); and

(E) Useable groundwaters are protected utilizing one (1) of the following methods:

(i) Set a drillable, retrievable, or other type of mechanical bridge plug above the producing interval in the cemented portion of the production casing, but at least one hundred fifty feet (150’) below the base of the lowest usable groundwater in the area, and secured at the surface with a wellhead and valve in operable condition;

(ii) Set a packer run on tubing above the producing interval in the cemented portion of the production casing, but at least one hundred fifty feet (150’) below the base of the lowest usable groundwater in the area, and secured at the surface with suitable wellhead packoff equipment and closed to the atmosphere or with a wellhead and valve in operable condition;

(iii) Run a casing inspection log confirming the mechanical integrity of the production casing and secured at the surface with a wellhead and valve in operable condition; or

(iv)(a) Conduct a fluid level test by wireline or other approved electronic or mechanical means which determines that the static fluid level is at least one hundred fifty feet (150’) below the base of the lowest usable groundwater in the area, and upon no less than forty-eight (48) hours notice prior to conducting the fluid level test, which may be witnessed by commission staff.

(b) The fluid level test shall be conducted annually within sixty (60) days prior to the anniversary date of the temporary abandonment during each year of the three-year temporary abandonment period.

(4)(A) Failure to maintain any of the above conditions may result in the issuance of a notice of violation (NOV).

(B) Failure of the permit holder to comply with the NOV or other applicable final administrative decision in accordance with 15 CAR § 275-104 shall:

(i) Result in the revocation of the temporary abandonment status; and

(ii) Require the well to be plugged in thirty (30) days, unless an extension of time to plug is granted after notice and hearing.

(5) Wells returning to active status from temporary abandonment status shall file for authorization to commence production operations on a form prescribed by the director.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book; amended December 16, 2007; amended February 19, 2009; amended November 19, 2018)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-208 Plugging methods and procedures {#sec-15-car-275-208 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-208}

15 CAR § 275-208. Plugging methods and procedures.

The methods and procedures for plugging a well shall be as follows:

(1)(A) The bottom of the hole shall be filled to the top of each producing stratum and a cement plug of not less than one hundred feet (100’) in length shall be placed inside the casing immediately above each producing stratum, or a bridge plug, regular, or wireline type, may be placed at the top of each producing stratum.

(B)(i) In the event bridge plugging is to be used for permanent abandonment, the bridge plug must be covered with a minimum of ten feet (10’) of cement.

(ii) The casing must be free from openings except perforations for the injection or producing formation, and the casing well bore annulus must be filled with cement to fifty feet (50’) above the top of the formation;

(2)(A) A cement plug not less than one hundred feet (100’) in length shall be placed at approximately fifty feet (50’) below all freshwater-bearing stratum when the surface casing is not cemented below the base of the freshwater-bearing stratum.

(B) In the event the surface casing has been cemented below the base of the freshwater-bearing stratum, a one hundred foot (100’) cement plug shall be placed inside the base of the surface casing;

(3) A plug shall be placed at the surface of the ground in each hole plugged in such manner as not to interfere with soil cultivation;

(4) The interval between plugs shall be filled with an approved heavy mud-laden fluid;

(5)(A) An uncased rotary drilling hole shall:

(i) Have a cement plug of not less than one hundred feet (100’) placed immediately above the Smackover limestone zone and any known productive zone in the area; and

(ii) Be filled with approved heavy mud up to the base of the surface casing and a plug of not less than one hundred feet (100’) of cement placed inside the base of the surface casing, provided the casing is cemented through the base of the freshwater-bearing stratum.

(B) A cement plug of not less than one hundred feet (100’) in length shall be placed at a point fifty feet (50’) below the base of the freshwater-bearing stratum in the event the surface casing is not cemented through the base of the freshwater-bearing stratum.

(6) Any other method approved by the Oil and Gas Commission may be used.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-209 Dry gas well plugging methods and procedures {#sec-15-car-275-209 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-209}

15 CAR § 275-209. Dry gas well plugging methods and procedures.

(a) Definitions. As used in this section:

(1) "Cased well" means a well in which production casing has been set and cemented;

(2) "Cement" means a Class A or Class H neat cement with a minimum weight of fourteen and one-half pounds per gallon (14.5 lbs./gal.), unless the cement contains additives which:

(A) Improve the ability of the cement to provide necessary protection; and

(B) Maintains a minimum compressive strength of five hundred pounds per square inch (500 psi) after seventy-two (72) hours;

(3) "Circulation method" means placement of cement used in plugging a well by circulating cement by positive pressure displacement through tubing set at a specified depth in the well;

(4) "Dump bailer method" means placement of cement used in plugging a well by using a dump bailer on a wire line;

(5) "General oilfield waste" means oily rags, chemical containers including any unused chemicals, oil filters and gaskets, used motor oil, lubricating oils, hydraulic fluids, diesel fuels, paint and solvent wastes, and other similar wastes generated during drilling, completion, production, workover, and plugging activities, and which are not exempt from the provisions of Subtitle C of the Federal Resource Conservation Recovery Act of 1976, Pub. L. No. 94-580;

(6)(A) "Mud" means only a freshwater-based drilling mud with a minimum weight of nine pounds per gallon (9 lbs./gal.) with a minimum viscosity of forty-five (45) seconds using API full funnel method.

(B) Mud may contain water (fresh or brine), Bentonite, Attapulgite, or other additives if they do not reduce the weight or viscosity below the required minimum;

(7) "Plugging fluid waste" means plugging fluids, including cement, that are generated from the well during plugging activities; and

(8) "Uncased well" means a well in which production casing has not been set, or is set but not cemented.

(b) Uncased wells.

(1) Uncased wells shall be plugged when required by 15 CAR § 275-207.

(2)(A) Notice of the plugging of uncased wells shall be given to the Oil and Gas Commission regional office where the well is located, in accordance with 15 CAR § 275-207.

(B) Following initial notice to the commission regional office, additional requirements concerning the well plugging operation may be given to the permit holder or the permit holder’s authorized representative.

(3) Uncased wells where intermediate casing has been set shall be subject to all the required plugging time frames for uncased wells and the applicable plugging requirements for cased wells in subsection (c) of this section, below, with respect to the protection of freshwater and oil and gas zones.

(4) Plugging requirements.

(A) The uncased well bore shall be filled with mud from the total depth of the well to the base of the surface casing prior to commencing plugging operations.

(B) Any zones which have been productive of oil and/or gas occurring in wells within one-half (1/2) mile of the uncased well, shall have a one hundred foot (100’) cement plug placed above each such correlated interval in the uncased well.

(C) A zone which contains any amount of hydrogen sulfide gas, or any other zone within the well which does not contain hydrogen sulfide gas, but hydrogen sulfide gas is present within the same zone within any well within one-half (1/2) mile, shall be covered:

(i) At a minimum, with a cement plug from one hundred feet (100’) below to one hundred feet (100’) above the zone; or

(ii) With a greater amount of cement sufficient to shut off and control the flow of hydrogen sulfide gas.

(D) If surface casing has been set to a depth of at least five hundred feet (500’) in the well, a one-hundred-foot cement plug shall be placed, utilizing the circulation method, from a depth of fifty feet (50’) below the base of the surface casing or from the depth of any deeper freshwater well within one-half (1/2) mile of the dry hole, and extending fifty feet (50’) into the cemented surface casing.

(E) If surface casing has not been set to a minimum depth of five hundred feet (500’) in the well, a cement plug shall be placed from a depth of at least five hundred feet (500’) or from the depth of any deeper freshwater well within one-half (1/2) mile of the dry hole, extending to fifty feet (50’) into the cemented surface casing.

(F) Any zones not covered by the surface casing plug specified above which produced water during the drilling or subsequent plugging operations shall be covered at a minimum with a cement plug from fifty feet (50’) below to fifty feet (50’) above the zone or a greater amount of cement sufficient to shut off the flow of water.

(G) A cement plug shall be placed from a minimum depth of fifty feet (50’) to a depth of three feet (3’) below the surface of the ground and the casing cutoff three feet (3’) below the ground surface, or deeper if surface use conditions indicate, and a plate welded onto the top of the casing and the remaining wellbore filled with soil and leveled in such manner as not to interfere with soil cultivation or surface use.

(5)(A) In the case of lost tools or stuck drill pipe, every reasonable attempt should be made to recover the tools or drill pipe, at least to a depth of the required surface casing plug, and the required surface casing plugs placed as required above.

(B) In the event the lost tools or stuck drill pipe cannot be recovered from a depth below the required depth of the surface casing plug, the Director of Production and Conservation may vary the plugging requirements of this subdivision (b)(5) and specify alternative plugging requirements.

(C) In determining whether to approve, and in selecting an alternative plugging requirement, the director shall consider:

(i) The potential for damage to fresh water;

(ii) The depth of the lost tools or equipment in relation to the depth of freshwater zones;

(iii) Well construction characteristics; and

(iv) The potential for upward migration of wellbore fluids into the fresh groundwater.

(1) Cased wells shall be plugged when required by 15 CAR § 275-207.

(2) Notice of the plugging of cased wells shall be given to the commission regional office where the well is located, in accordance with 15 CAR § 275-207.

(3) Plugging requirements.

(A) The wellbore shall be filled with mud from total depth of the well to the base of the surface casing prior to commencing plugging operations.

(B) Cast iron bridge plugs may be set above the lowermost perforated interval or between perforated intervals prior to filling the wellbore with mud, in which case the wellbore need only be filled with mud from the top of the uppermost cast iron bridge plug to the base of the surface casing prior to commencing plugging operations.

(i) Be placed from fifty feet (50’) below, or total depth if well bore did not extend to a point fifty feet (50’) below; and

(ii) Extend across the perforated interval to a point fifty feet (50’) above each perforated interval.

(D)(i) If using the dump bailer method, a cast iron bridge plug shall be placed inside the cemented portion of the production casing immediately above each perforated interval, with each bridge plug covered with a minimum of ten feet (10’) of cement.

(ii) In the alternative, a cast iron bridge plug may be placed over the lower most perforated interval and the wellbore casing filled with cement to a point fifty feet (50’) above the top of the uppermost perforated interval, provided the production casing/wellbore annulus is filled with cement to a point fifty feet (50’) above the uppermost perforated interval.

(E)(i) If cement is not present on the outside of the production casing at the location of each required cement plug, specified in subdivisions (c)(3)(F) – (H) of this section, below, cement shall be placed on the outside of the production casing in the production casing/wellbore annulus from a point fifty feet (50’) below, or total depth if the well bore did not extend to a point fifty feet (50’) below, and extending across the required interval to be plugged, to a point fifty feet (50’) above each required interval to be plugged.

(ii) However, the director may approve alternative, but equally protective, placement of cement plugs, open-hole devices, or plugging materials when necessary due to well construction limitations.

(F)(i) Any zones not covered by the surface casing which produce water during the plugging operation or are known to be significant water producing formations or which are known to be over-pressured, shall be covered at a minimum with a cement plug from fifty feet (50’) below to fifty feet (50’) above the zone or a greater amount of cement sufficient to shut off the flow of water.

(ii) The director may approve alternative, but equally protective, plugging materials or other open-hole devices sufficient to shut off the flow of water.

(G) If surface casing has been set to a minimum depth of five hundred feet (500’) in the well, a one-hundred-foot surface casing cement plug shall be placed on the outside and inside of the production casing if production casing is not removed from a depth of fifty feet (50’) below the base of the surface casing, or from the depth of any deeper freshwater well within one-half (1/2) mile of the wellbore, and extend fifty feet (50’) into the cemented surface casing.

(H)(i) If surface casing has not been set to a minimum depth of five hundred feet (500’) in the well, a cement plug shall be placed on the outside and inside of the production casing if production casing is not removed from a depth of at least five hundred feet (500’), or from the depth of any deeper freshwater well within one-half (1/2) mile of the well bore, and extend fifty feet (50’) into the cemented surface casing present in the wellbore.

(ii) However, if it can be demonstrated that no freshwater-bearing zones are present below the existing surface casing set in the well, the director may approve an alternative surface casing plug extending from fifty feet (50’) below the existing surface casing and extending fifty feet (50’) into the cemented surface casing present in the wellbore.

(I)(i) The casing shall be cut off three feet (3’) below the ground surface, or deeper if surface use conditions indicate, and a plate welded onto the top of the casing and the remaining wellbore filled with soil and leveled in such manner as not to interfere with soil cultivation or surface use.

(ii) A cement plug not less than three feet (3’) shall be also be placed below the plate that is welded onto the top of the casing.

(4) Foreign material prohibited.

(A) Except for an unavoidable loss of drilling and logging tools, production equipment, or the presence of damaged casing obstructing the wellbore, placing or lodging any material or substance in an unplugged well to either fill or bridge the hole for the purpose of avoiding proper plugging procedures is prohibited.

(B) Foreign materials which have been placed in the hole shall be removed before plugging operations are commenced.

(5) Plugging a bridged well.

(A) When a well becomes obstructed because of the loss of drilling or logging tools or producing equipment which would be impractical to remove, the director may vary the plugging requirements of this subdivision (c)(5) and specify alternative plugging requirements.

(B) In determining whether to approve and in selecting alternative plugging requirements, the director shall consider the:

(i) Time and cost of removing lost tools or equipment;

(ii) Potential for damage to fresh water;

(iii) Depth of the lost tools or equipment in relation to the depth of freshwater zones;

(iv) Well construction characteristics; and

(v) Potential for upward migration of wellbore fluids into the fresh groundwater.

(d) Horizontal well plugging procedures.

(1) For an uncased well, the plugging procedures shall be in accordance with subsection (b) of this section, above, with the exception that:

(A) The production interval plug shall be placed at the beginning of the well curve kick-off point and the required cement placed or extended above that point; and

(B) Oil-based drilling mud may be used to fill the horizontal lateral of the wellbore up to the kick-off point provided the kick-off point is below any known fresh groundwater.

(2) For a cased well, the plugging procedures shall be in accordance with subsection (c) of this section, above, with the exception that:

(A) The production interval plug shall be placed at the beginning of the well curve kick-off point and the required cement placed or extended above that point; and

(B) Oil-based drilling mud may be used to fill the horizontal lateral of the wellbore up to the kick-off point provided the kick-off point is below any known fresh groundwater.

(3)(A) If a vertical pilot hole is drilled below the well curve kick-off point, and the pilot hole encountered another producing interval in the vertical pilot hole below the kick–off point, a one-hundred-foot cement plug shall be placed above each such correlated interval encountered in the vertical pilot hole prior to drilling the horizontal portion of the well, unless approval has been granted to produce the other interval encountered in the pilot hole in accordance with applicable general rules or order of the commission.

(B) Additionally, the director may approve alternative forms of zonal isolation based on the productive potential of the isolated zone.

(4) Well site cleanup shall be in accordance with subsection (e) of this section, below.

(e) Well site cleanup.

(1) When plugging a well, the permit holder shall provide at least one (1) pit as described in subdivision (e)(2) of this section, below, or leak-free, aboveground, portable container into which plugging fluid wastes shall be deposited.

(2)(A) Plugging pits shall be constructed with sufficient capacity to contain all plugging fluid wastes within the pits, and maintained in a manner that reasonably prevents overflow during plugging operations.

(B) Plugging pits shall be used only for the temporary storage of plugging fluid wastes, and shall not be used for the disposal of general oilfield wastes.

(3)(A) All general oilfield wastes generated during plugging activities shall be:

(i) Temporarily stored in on-site containers; and

(ii) Removed from the site at the conclusion of plugging activity.

(B) General oilfield wastes shall not be disposed of through on-site burial or in plugging pits.

(4)(A) All plugging pits shall be filled and graded within thirty (30) days after conclusion of plugging activities unless an extension has been granted by the director.

(B) All plugging pits shall be closed allowing no subsidence or leakage of fluids, and, where applicable, with sufficient compaction to support agriculture or forestry machinery.

(5) All production equipment, concrete bases, machinery, and equipment debris shall be removed from the site.

(6) Any drilling rat holes shall be filled with mud to a depth of ten feet (10’) below the surface, at which point a cement plug shall be placed from ten feet (10’) to three feet (3’) below ground level and leveled to the surface with soil.

(7) Any other excavations shall be filled and the overall well site graded or contoured to prevent erosion.

(f) Alternative plugging methods may be authorized by the director provided the same or equal level of protection for the freshwater and oil and gas zones can be maintained.

History

Codification Notes: “API” means American Petroleum Institute.This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Original rule Repealed Effective October 15, 2006; new rule March 25, 2010; amended October 1, 2015)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-210 Seismic core and other exploratory holes to be plugged — Methods — Records {#sec-15-car-275-210 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-210}

15 CAR § 275-210. Seismic core and other exploratory holes to be plugged — Methods — Records.

(a) Before any hole is abandoned which is drilled for seismic, core, or other exploratory purposes below the freshwater formation, it shall be the duty of the owner or driller of any such hole to plug the same in such manner as to properly protect all water-bearing formations.

(b) Core holes.

(1) Core holes shall comply with the minimum surface casing and plugging requirements.

(2) No core hole shall be completed as a producing well.

(3) A plugging record shall be filed no later than thirty (30) days from the date drilling operations commence.

(4)(A) A copy of all electric logs shall be filed with the Oil and Gas Commission no later than one (1) year from the date drilling operations commence.

(B) In the event an electric log was not run, the operator shall file a copy of a driller’s log.

(5) All information required to be filed shall be kept confidential for a period of one (1) year from the date drilling operations commence.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-211 Domestic natural gas wells and conversion of permitted oil and natural gas wells for use as domestic natural gas or freshwater supply wells {#sec-15-car-275-211 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-211}

15 CAR § 275-211. Domestic natural gas wells and conversion of permitted oil and natural gas wells for use as domestic natural gas or freshwater supply wells.

(a) Domestic natural gas wells.

(1)(A) Any well drilled by persons for use as a domestic, livestock, or agriculture natural gas source, is not under the jurisdiction of the Oil and Gas Commission and is not subject to permitting or regulation by the commission, provided such natural gas is not sold or gathered for sale to others.

(B) Such wells may be subject to other applicable state laws.

(2) If the gas produced from a well operating as a domestic use well is gathered for resale to others, that well is under the jurisdiction of the commission and shall be subject to:

(A) All applicable regulatory requirements of the commission; and

(B) Any other applicable state laws regarding the production, gathering, and distribution of natural gas for use by consumers.

(b) Domestic use transfers after November 16, 2008.

(1) A controlled natural gas production well required to be permitted by the commission may be transferred to a surface owner for use as a domestic natural gas supply well if the well has not produced commercial quantities of natural gas during the previous twenty-four (24) calendar months provided:

(A) The operator files, on a form prescribed by the Director of Production and Conservation, a request to transfer the well to the surface owner, which shall include written documentation from the surface owner accepting transfer of the well for use as a domestic natural gas supply well;

(B) A statement by the surface owner and the operator that the natural gas from the well will be used on the property where the well is located and that any natural gas production from the well will not be sold; and

(C) Written documentation from all owners, as defined in Arkansas Code § 15-72-102(9), and all mineral owners in the drilling unit upon which the well is located, stating that they do not object to the transfer of the well to the surface owner.

(2) An oil or natural gas production well may be transferred to a surface owner for use as a domestic or livestock freshwater supply well provided:

(A) The operator files, on a form prescribed by the director, a request to transfer the well to a surface owner prior to commencing plugging operations, which shall include written documentation from the surface owner accepting transfer of the well for use as a freshwater supply well;

(B) The well is plugged in accordance with current commission plugging requirements with respect to all oil and natural gas producing zones and a cement plug is placed, on the inside and outside of the production casing if left in the well, from one hundred feet (100’) below the base of the fresh water extending up to the base of the fresh water in the well; and

(3)(A) Following completion of the above domestic use well transfer requirements, all regulatory oversight of the well by the commission shall terminate and the well shall become the sole responsibility of the surface owner.

(B) The well shall be subject to any applicable state laws regarding private freshwater wells or domestic natural gas supply wells administered by state and/or federal agencies other than the commission.

(c)(1) Uncontrolled natural gas production wells may not be transferred for domestic use unless otherwise approved by the commission after notice and a hearing.

(2) Notice shall be given to all owners as defined in Arkansas Code § 15-72-102(9), and all mineral owners in the leasehold upon which the well is located.

(3) Any person requesting a transfer of an uncontrolled natural gas production well shall file an application in accordance with 15 CAR §§ 275-101 and 275-102, and other applicable hearing procedures.

(d) Domestic use transfers prior to November 16, 2008. Any natural gas production well transferred to a surface owner for use as a domestic natural gas supply well prior to November 16, 2008, shall no longer be subject to the regulatory oversight by the commission as long as the natural gas from the well is used only on the property where the well is located and that any natural gas production from the well is not sold.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book; amended November 16, 2008; amended May 18, 2012)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-212 Organization reports {#sec-15-car-275-212 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-212}

15 CAR § 275-212. Organization reports.

(a)(1) Every person or entity engaged in any operation or activity regulated by the Oil and Gas Commission, shall file with the commission an organization report on a form prescribed by the Director of Production and Conservation, prior to engaging in the operation or activity.

(2) At a minimum, the form shall include:

(A) Name of person or entity and type of operation or operations being conducted;

(B)(i) An official mailing address to which all correspondence from the commission is to be sent.

(ii) If the official mailing address is to be sent to a registered agent for the person or entity, then the name of the registered agent must also be included;

(C) A list of official telephone numbers, facsimile numbers, and email addresses for which contact by the commission may be made;

(D) The type of entity and a list of all persons authorized to submit required forms, reports, and other documents for the entity;

(E) A statement that the person or entity is authorized to conduct business within the state; and

(F) Any other information deemed necessary by the director.

(b) Every person or entity shall file an updated organization report with the commission on or before July 1 of every calendar year.

(c) After any change occurs as to facts stated in the report filed, a supplementary report shall be filed with the commission within thirty (30) days of any change.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book; amended January 22, 2009)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-213 Casing requirements {#sec-15-car-275-213 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-213}

15 CAR § 275-213. Casing requirements.

(a) In all established fields, casing requirements shall be governed by the specific field rules for that field, and are not superseded by this section.

(b)(1)(A) All freshwater sands shall be fully protected by the setting and cementing of surface casing to prevent the freshwater sands from becoming contaminated with oil, gas, or salt water.

(B) Surface casing shall be set and cement circulated to the surface utilizing the pump and plug method.

(2) The minimum surface casing requirements for wildcat wells or wells not covered by field rules, in the counties of Ashley, Bradley, Calhoun, Columbia, Hempstead, Lafayette, Miller, Nevada, Ouachita, and Union, are as follows:

TVD of Well Amount of Surface Casing 0’ – 3,000’ 100’ 3,001’ – 4,000’ 160’ 4,001’ – 5,000’ 300’ 5,001’ – 6,500’ 500’ 6,501’ – 7,500’ 750’ 7,501’ – 8,500’ 1,000’ 8,501’ – 10,500’ 1,250’ 10,501’ & below 1,500’

(3) The minimum surface casing requirements for wildcat wells or wells not covered by field rules, in the counties of Crawford, Franklin, Johnson, Logan, Madison, Pope, Scott, Sebastian, Washington, and Yell, are as follows:

TVD of Well Amount of Surface Casing 0’ – 1,500’ 100’ 1,501’ – 3,000’ 200’ 3,001’ – 6,500’ 500’ 6,501’ – 10,000’ 800’ 10,001’ & below 1,000’

(4) The minimum surface casing requirements for wildcat wells or wells not covered by field rules, in the counties of Cleburne, Conway, Faulkner, Independence, Jackson, Searcy, Stone, Van Buren, and White, shall be to a depth of five hundred feet (500’) or the top of the Paleozoic age rock sequence, whichever is greater.

(5) The minimum surface casing requirements for wildcat wells or wells not covered by field rules, in the counties of Arkansas, Lonoke, Monroe, Prairie, and Woodruff, shall be to a depth of one thousand two hundred fifty feet (1,250’).

(6) The minimum surface casing requirements for wildcat wells or wells not covered by field rules, in the counties of Crittenden, Cross, Lee, Phillips, and St. Francis, shall be to a depth of two thousand feet (2,000’).

(c)(1) A producing string of casing shall be:

(A) Set at least to the top of the producing formation; and

(B) Cemented so that the calculated fill, after allowing for twenty-five percent (25%) excess, will be at least two hundred fifty feet (250’) above the top of any productive interval.

(2) Cementing shall be done by the pump and plug method.

(3) Cement shall be allowed to set a minimum of twenty-four (24) hours before drilling the plug.

(d)(1) The director may grant exceptions to the above requirements if conditions exist that require more than these requirements for the purpose of safety or for the protection of freshwater sands and oil or gas bearing sands or may establish minimum surface casing requirements in future producing areas not covered by this section.

(2) Director’s notice to Fayetteville Shale operators – June 1, 2015, (supersedes previous version of June 1, 2011).

(A)(i) Unless an exception is granted, all operators of all wells spud after May 22, 2015, or permitted on or after June 1, 2015, in Cleburne, Conway, Faulkner, Independence, Jackson, Searcy, Stone, Van Buren, and White counties, and Fayetteville Shale wells only in Pope County, shall comply with casing and cementing requirements based on the zone in which the well is located.

(ii) Please contact the El Dorado regional office for the zone map.

(B) The well casing and cementing requirements are as follows:

(i) Surface casing shall be set to a depth equal to five hundred feet (500’) below the lowest ground surface elevation occurring within one (1) mile of the proposed well, with a minimum of one thousand feet (1,000’) of surface casing required to be set and cemented to surface;

(ii) Production casing shall be set to at least the top of the producing formation, and cemented, such that the calculated top of cement (TOC), plus a twenty-five percent (25%) excess, shall be at a minimum of:

(a) One hundred feet (100’) above the surface casing shoe in Zone 1;

(b) Five hundred feet (500’) below the surface casing shoe in Zone 2; and

(iii)(a) If a gas bearing zone is encountered above the Fayetteville Shale in the subject well or in another well within a one-mile radius of the subject well, and the above cementing requirements do not result in at least two hundred fifty feet (250’) of cement placed above the shallow gas bearing zone, the TOC shall be increased to provide a minimum of two hundred fifty feet (250’) of cement above the shallower gas bearing zone.

(b) However, the additional cementing requirements in the subject well shall not result in the production casing TOC to extend more than one hundred feet (100’) above the surface casing shoe inside the surface casing.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book; amended September 16, 2006)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-214 Blowout prevention {#sec-15-car-275-214 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-214}

15 CAR § 275-214. Blowout prevention.

(a) All proper and necessary precautions shall be taken for keeping the well under control during drilling operations, including but not limited to the use of blowout preventers and high pressure fittings attached to properly anchored and cemented casing strings or maintain mud-laden fluid of sufficient weight to provide proper well control.

(b) Blowout preventers shall be tested at regular intervals to insure proper operation.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book; amended October 15, 2006)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-215 Well drilling pits and completion pits requirements {#sec-15-car-275-215 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-215}

15 CAR § 275-215. Well drilling pits and completion pits requirements.

(a) Applicability.

(1) This section applies to all pits constructed during the drilling, completion, and testing of a:

(A) Brine, oil, gas, or oil and gas production well;

(B) Brine injection or disposal well;

(D) Class II commercial disposal well.

(2) “Pits”, as used in context of this section, refer to the type of pits as defined in subsection (c) of this section, below.

(b) Joint enforcement.

(1) After the effective date of this section, any operator who constructs or operates a pit covered by this section shall be subject to the specific enforcement provisions under the respective authorities of the:

(A) Oil and Gas Commission; or

(B) Division of Environmental Quality.

(2) The regulation of the activities covered under this section by the commission and the division shall be in accordance with a Memorandum of Agreement (MOA) between the Oil and Gas Commission and the division.

(1) “APC&EC” means the Arkansas Pollution Control and Ecology Commission;

(2) “Closed loop system” means a system that uses a combination of solids control equipment incorporated in a series of steel tanks that eliminates the use of a pit;

(3) “Completion flowback fluid” means any of a number of liquid and gaseous fluids or mixtures of fluids, chemicals, and/or solids that flow from a well and consisting of drilling fluid, silt, debris, water, brine, oil scum, paraffin, or other materials which have been removed from the well bore during the initial completion of a well, but does not include frac flowback fluid;

(4) “Cuttings” means fragments of rock which are a result of the cutting action of the drill bit on rock formations encountered in the well which are transported to the surface by the drilling fluid;

(5) “DEQ” means the Division of Environmental Quality;

(6) “Discharge” means the release, overflow, leakage, or seepage of any fluids covered by this section;

(7)(A) “Drilling fluid” means any of a number of liquid and gaseous fluids and mixtures of fluids and solids (as solid suspensions, mixtures, and emulsions of liquids, gases, cuttings, and other solids) utilized during brine, oil, or gas drilling operations.

(B) Drilling fluid is generally synonymous with drilling mud, which:

(i) Typically contains:

(a) Bentonitic clays;

(b) Chemical additives;

(d) Lubricants;

(e) Emulsifiers; and

(f) Weighting materials; and

(ii) Encompasses most muds used in drilling operations, especially muds that contain significant amounts of:

(a) Suspended solids;

(b) Emulsified water; or

(8) “Director of the DEQ” means the Director of the Division of Environmental Quality or his or her designated representative;

(9) “Director of OGC” means the Oil and Gas Commission Director of Production and Conservation or his or her designated representative;

(10)(A) “Ecologically sensitive waterbody (ESW)” means waters that have been given the designated use of ecologically sensitive waterbody by the Arkansas Pollution Control and Ecology Commission.

(B) This beneficial use identifies segments known to provide habitat within the existing range of threatened, endangered, or endemic species of aquatic or semiaquatic life forms;

(11) “Encountered water” means water encountered during brine, oil, or gas drilling operations, which is of sufficient quantity to require disposal, and which is not produced water;

(12) “Exploration and production waste (E&P waste)” means wastes associated with the exploration, development, and production of brine, oil, or gas and which are not regulated by the provisions of, and, therefore, exempt from the federal Resource Conservation and Recovery Act, 42 U.S.C. § 6901, and may include, but are not limited to the following:

(A) Salt water (produced brine or produced water);

(B) Oil-based drilling fluids;

(D) Completion flowback fluid;

(E) Frac flowback fluid;

(F) Workover flowback fluid;

(G) Produced water;

(H) Rainwater from firewalls and pits at drilling and production facilities; and

(I) Other wastes not described above;

(13)(A) “Extraordinary resource waters (ERW)” means waters that have been given the designated use of extraordinary resource waterbody by the Arkansas Pollution Control and Ecology Commission.

(B) This beneficial use is a combination of the chemical, physical, and biological characteristics of a waterbody and its watershed which is characterized by:

(i) Scenic beauty;

(ii) Aesthetics;

(iii) Scientific values;

(iv) Broad scope recreation potential; and

(v) Intangible social values;

(14) “Frac flowback fluid” means fluids that consist of fresh water and solids such as sand or other proppant (resin or ceramic grains) or other additives that flow from a well following hydraulic fracturing of a well, until such time as the volume of fluid utilized for the hydraulic fracturing process in the well has been recovered;

(15)(A) “Natural and Scenic Waterways (NSW)” means waters that have been given the designated use of Natural and Scenic Waterways by the Arkansas Pollution Control and Ecology Commission.

(B) This beneficial use identifies segments which have been legislatively adopted into a state or federal system;

(16) “Nonhazardous oilfield wastes (NOW)” means fluids to be used or reused in connection with activities associated with the exploration, development, and production of brine, oil, or gas and includes, but is not limited to:

(A) Drilling fluids;

(B) Completion fluids;

(D) Chemicals used to detoxify brine, oil, or gas wastes;

(17) “OGC” means the Oil and Gas Commission;

(18) “Oil-based drilling fluid” means drilling fluids containing diesel or crude oil rather than fresh water as the main liquid phase of the drilling mud;

(19)(A) “Operator” means any person who has the primary management and ultimate decision-making responsibility over the operation of a facility or activity.

(B) The operator is responsible for ensuring compliance with all applicable rules and conditions;

(20) “Person” means:

(A) Natural person;

(B) Corporation;

(D) Municipality;

(E) Government;

(F) Governmental subdivision;

(G) Agency;

(H) Public or private corporation;

(I) Business trust;

(J) Estate;

(K) Trust;

(L) Individual;

(M) Partnership;

(N) Association; or

(O) Any other legal entity;

(21) “Pit” shall include:

(A) Circulation pit.

(i) A pit used during drilling where drilling fluids are circulated during drilling operations.

(ii) The circulation pit may be part of the mud pit.

(iii) Circulation pits may also refer to a series of open, aboveground tanks, usually made of steel;

(B) Completion pit.

(i) A pit used for storage of completion flowback fluid and drilling fluids or other materials which have been cleaned out of the well bore during the initial completion of a well.

(ii) Circulation or mud pits may be used as completion pits when drilling operations conclude;

(i) A pit used for containing fluids at an operating well during an actual emergency and for a temporary period of time.

(ii) Use of the emergency pit is necessitated due to unplanned operational issues, which may include but is not limited to, a:

(a) Temporary shutdown of a disposal well or fluid injection well or associated equipment;

(b) Temporary overflow of saltwater storage tanks on a producing lease, gas flaring, cement circulation; or

(D) Mud pit.

(i) A pit or series of pits used during drilling where fluids are mixed and circulated during drilling operations.

(ii) Mud pits may also refer to a series of open, aboveground tanks, usually made of steel;

(E) Reserve pit.

(i) A pit not part of the active circulation system, used to store drilling fluids or to contain fluids generated during drilling operations.

(ii) Such fluids would include, but not be limited to:

(a) Cuttings;

(b) Drilling fluids; and

(F) Test pit. A pit constructed for use during a well test; and

(G) Workover pit. A pit used for storage of completion flowback fluid, workover flowback fluid, and other materials which have been cleaned out of the well bore during any subsequent completion or recompletion;

(22) “Pollution” means such contamination or other alteration of the physical, chemical, or biological properties of any waters of the state, or such discharge of any liquid, gaseous, or solid substance in any waters of the state as will, or is likely to, render the waters harmful, detrimental, or injurious to:

(A) Public health, safety, or welfare;

(B) Domestic, commercial, industrial, agricultural, recreational, or other legitimate beneficial uses; or

(23) “Produced water” means water produced from any productive or potentially productive brine, oil, or gas producing interval in the well, which is not:

(A) Completion flowback fluid;

(B) Frac flowback fluid;

(D) Encountered water;

(24) “Stormwater” means:

(A) Rainwater runoff;

(B) Snow melt runoff; and

(25) “Water-based drilling fluid” means drilling fluid containing fresh waters rather than diesel or crude oil as the liquid component of the drilling mud;

(26) “Waters of the state” means all streams, lakes, marshes, ponds, watercourses, waterways, wells, springs, irrigation systems, drainage systems, and all other bodies or accumulations of water, surface and underground, natural or artificial, public or private, which are contained within, flow through, or border upon this state or any portion of the state;

(27) “Water table” means the surface between the zone of saturation and the zone of aeration and the surface of a body of unconfined groundwater at which the pressure is equal to that of the atmosphere; and

(28) “Workover flowback fluid” means any of a number of liquid and gaseous fluids and mixtures of fluids, chemicals, and/or solids consisting of drilling fluid, silt, debris, water, brine, oil scum, paraffin, or other materials which are removed from the well bore during the subsequent or recompletion of a well.

(d) Commencement of construction operations.

(1) The operator shall notify the appropriate Oil and Gas Commission regional office, via mail, email, or fax at least forty-eight (48) hours prior to the commencement of pit construction operations.

(2) The notice of commencement (NOC) shall be on a form agreed upon by the Oil and Gas Commission and the division and shall include, at a minimum, the:

(A) Operator information (name, address, and emergency contact phone number);

(B) Location of the drill pad site (latitude and longitude in degrees, minutes, seconds, and county, section, range, and township, including the quarter (1/4) of the quarter (1/4) position within the section);

(D) Approximate distance to the nearest waters of the state;

(E) Type of fluid system and type of drilling fluids to be used;

(F) Well name;

(G) Nearest city/town; and

(H) Approximate date pit construction operations shall commence.

(3) Upon receiving the notice of commencement, the Oil and Gas Commission shall forward a copy to the division, Department of Health, and the county judge of the county in which the pit is located.

(4) Oil and Gas Commission and division staff may conduct site inspections as deemed necessary.

(e) Discharges prohibited.

(1) The discharge from a pit or any activity associated with the drilling or completion of a well to any surface or groundwaters or in a location where it is likely to cause pollution to any surface or groundwaters is prohibited.

(2) Such discharge may subject the operator to division enforcement actions under the provisions of the Water and Air Pollution Control Act, Acts 1949, No. 472, as amended, Arkansas Code § 8-4-101 et seq., and enforcement actions of the Oil and Gas Commission under Acts 1939, No. 105, as amended.

(3) Any discharge must be reported within twenty-four (24) hours to the Oil and Gas Commission and the division.

(4) Leakage from any pit is considered an unauthorized discharge.

(f) Mud, circulation, and reserve pit construction requirements.

(1) General requirements.

(A) Mud, circulation, and reserve pits constructed within the one-hundred-year flood plain must be in accordance with any county or other local ordinance or requirement pertaining to the one-hundred-year flood plain.

(B)(i) The location of all mud, circulation, or reserve pits shall be chosen with reasonable consideration to maximizing the distance from surface waters.

(ii) Mud, circulation, or reserve pit construction in streams, creeks, lakes, or any other waterbodies is strictly prohibited.

(C) Any mud, circulation, or reserve pit construction in wetlands must receive appropriate prior authorization from the United States Army Corps of Engineers.

(D) In areas other than jurisdictional wetlands referenced in subdivision (f)(1)(C) of this section, above, where the water table is ten feet (10’) or less below the ground surface, all mud, circulation, or reserve pits shall be constructed aboveground, or the operator shall use a closed loop system.

(2) Reserve pit requirements.

(A)(i) All reserve pits shall be:

(a) Constructed with a minimum of two feet (2’) of freeboard; and

(b) Maintained to handle a storm event up to a ten-year, twenty-four-hour storm event during the operation of the reserve pit.

(ii)(a) Reserve pits constructed above ground utilizing bermed side walls shall be constructed with a minimum of two feet horizontal to one foot vertical (2’:1’) side slope on both the interior and exterior walls.

(b) The top of the bermed pit walls must be a minimum of two feet (2’) wide.

(B) All reserve pits shall be constructed with a liner using one (1) of the following methods:

(i)(a) A synthetic liner of at least twenty (20) mils thickness, with a four-inch welded seam overlap, completely covering the reserve pit bottom and inside walls.

(b) Sand or sandy material must be placed below the liner if a rocky or uneven surface is encountered.

(c) The synthetic liner must be protected from deterioration, punctures, and/or any activity which may damage the integrity of the synthetic liner;

(ii)(a) A compacted clay liner may be applied to the bottom and sides of the reserve pit to create an impervious/impermeable barrier.

(b) Construction of the reserve pit and compacted clay liner shall be in accordance with sound construction and engineering principles designed and constructed to prevent any leakage or seepage to water of the state, with due consideration given to the:

(1) Topography;

(2) Pit material composition; and

(3) Availability of liner materials.

(c) The clay used to construct the liner may be in situ or mixed with additional off-site materials, if the on-site clay is inadequate; or

(iii) Other materials or methods used for liner construction must be approved by both the Director of the Division of Environmental Quality and the Director of Production and Conservation prior to use.

(3) Mud and circulation pits.

(A) Closed loop systems may be used for mud and circulations pits and must be maintained in a leak-free condition.

(B) Earthen mud and circulation pits shall be:

(i) Constructed with a minimum of two feet (2’) of freeboard; and

(ii) Maintained to handle a storm event up to a ten-year, twenty-four-hour storm event during the operation of the mud or circulation pit.

(i)(a) A synthetic liner of at least twenty (20) mils thickness, with a four-inch welded seam overlap, completely covering the reserve pit bottom and inside walls.

(b) Sand or sandy material must be placed below the liner if a rocky or uneven surface is encountered.

(c) The synthetic liner must be protected from deterioration, punctures, and/or any activity which may damage the integrity of the synthetic liner;

(ii)(a) Bentonite drilling mud from freshwater-based drilling fluids may be used on the bottom and sides of the earthen mud or circulation pit to create an impervious/impermeable barrier.

(b) Application of the mud or circulation pit bentonite drilling mud liner shall be in accordance with sound construction and standard industry practices designed and constructed to prevent any discharge; or

(iii)(a) A concrete liner may be applied to the bottom and sides of the earthen mud or circulation pit to create an impervious/impermeable barrier.

(b) Construction of the mud or circulation pit concrete liner shall be in accordance with sound construction and standard industry practices designed and constructed to prevent any discharge.

(D) Oil-based drilling fluids shall not be placed in an earthen mud or circulation pit unless the pit is lined with a synthetic or concrete liner as prescribed in subdivision (f)(3)(C)(i) or subdivision (f)(3)(C)(iii) of this section, above.

(E) If oil-based drilling fluids are to be used, and the location of the mud or circulation pit is within one hundred feet (100’) of a pond, lake, stream, ERW, ESW, or NSW, the operator is required to use a closed loop system.

(g) Operating requirements for mud, circulation, or reserve pits.

(1) No waste oil, hydraulic fluids, transmission fluids, trash, or any other miscellaneous rig waste may be placed, stored, or disposed into a mud, circulation, or reserve pit.

(2) Produced water and frac flowback fluid may not be placed, stored, or disposed in a mud, circulation, or reserve pit, except that as part of a frac flowback fluid recycling program, frac flowback fluids, and, upon approval of both the Director of Production and Conservation and the Director of the Division of Environmental Quality, produced water may be temporarily placed or stored in a reserve pit for a period not to exceed ninety (90) days per pit use for this purpose if:

(A) The reserve pit is constructed with a clay liner as specified in subdivision (f)(2)(B)(ii) of this section, above, and a synthetic liner of at least forty (40) mils thickness, or two (2) twenty-mils-thickness synthetic liners, in addition to all other applicable reserve pit construction requirements as specified in subdivision (f)(2) of this section, above, and have a means to monitor between the synthetic liners (if two (2) liners are utilized) and below the bottom of the lower most synthetic liner;

(B)(i) The operator requests approval from the division in writing prior to the placement or storage of the frac flowback fluid or approved produced water in a reserve pit.

(ii) Such request shall include:

(a) The Oil and Gas Commission well permit number;

(b) Well name;

(d) Anticipated dates of use;

(e) Volume of water to be stored or placed; and

(f) Detailed information on any proposed pipelines for the transfer of frac flowback fluids, including a map showing proposed pipeline location; and

(C) No frac flowback fluids or other fluids mixed with frac flowback fluids temporally stored or placed in a reserve pit may be sent to any commercial land applications disposal facility or land applied on site.

(3) Water-based drilling fluid, stormwater, water from waters of the state, or encountered water may be placed or stored in an earthen mud, circulation, or reserve pit.

(4)(A) Mud, circulation, and reserve pits must be maintained in such a manner as to prohibit any discharges.

(B) The operator is required to maintain adequate storage capacity at all times.

(5)(A) Mud, circulation, and reserve pit levees or walls shall be protected and maintained at all times to prevent deterioration or discharge.

(B) In addition, pit liners shall also be maintained and protected from deterioration or puncture causing discharge of fluids until such time that the pit is emptied and closed.

(6)(A) Mud, circulation, and reserve pits shall contain only drilling fluids generated during the drilling of the well or wells at the drilling pad where the pit is constructed, except that as part of a frac flowback fluid recycling program, a reserve pit, permitted in accordance with subdivision (g)(2) of this section, above, may temporarily contain frac flowback fluids, and, upon approval by both the Director of Production and Conservation and the Director of the Division of Environmental Quality, produced water, which may be transferred to another drill pad reserve pit permitted in accordance with subdivision (g)(2) of this section, above.

(B) The transfer of frac flowback fluids and approved produced water via tank truck shall be in accordance with 15 CAR § 275-503.

(C) If the transfer of frac flowback fluids and approved produced water is via pipeline, such pipeline shall be constructed and maintained in a leak-free condition and protected from:

(i) Deterioration;

(ii) Punctures; and/or

(iii) Any activity which may damage the integrity of the pipeline.

(D) If the proposed pipeline will result in a stream crossing, a short-term activity authorization shall be received from the division prior to construction.

(E) Any discharge from the pipeline shall be reported immediately to the division.

(7)(A) In the event of an emergency and with prior approval from either the Director of the Division of Environmental Quality or the Director of Production and Conservation, the reserve pit may be used for temporary additional storage of water-based drilling fluids from another drilling pad location.

(B)(i) In the event of an emergency, any request for approval must be submitted to both the division and the Oil and Gas Commission for review.

(ii) The division or the Oil and Gas Commission will provide notice to each other at the time of the approval of any request made pursuant to this subdivision (g)(7).

(8) Except as specified in subdivision (i)(1) of this section, or in an emergency and with prior approval from the Director of the Division of Environmental Quality, hauling or transporting drilling fluids from a pit to an off-site location not located on a drilling pad, for additional storage, is prohibited.

(9) Oil-based drilling fluids shall be segregated from water-based drilling fluids and other drilling fluids.

(h) Fluid disposal and earthen pit closure requirements for water-based drilling fluid and encountered water.

(1) Water-based drilling fluid, stormwater, water from waters of the state, or encountered water stored in the pits shall be removed to the maximum extent practical using pumps or similar equipment at the time of pit closure, and shall be disposed of in one (1) of the following manners:

(A) Land applied in accordance with an active division land application permit;

(B) Disposed of fluid into approved NPDES or state-permitted facility;

(D) Pumping the water-based drilling fluids back down the well bore of the well in accordance with Oil and Gas Commission requirements;

(E)(i) Water-based drilling fluids exhibiting high viscosity to high solids concentration may be solidified or stabilized by combining with available native soils and buried in situ.

(ii) The operator is responsible for ensuring the native soils are properly mixed to prevent any discharge;

(F) Transported by truck or by pipeline to a reserve pit which is part of an approved frac flowback fluid recycle program; and

(G) By any other method as approved by the division and the Oil and Gas Commission.

(2) The operator shall take all reasonable measures to ensure that drilling fluid and encountered water that is removed from the well site are properly transported to and disposed of or recycled or reclaimed at an Oil and Gas Commission or division permitted site or facility, or a permitted site or facility outside of Arkansas.

(3) Any synthetic liner used shall be removed to the fullest extent practicable and properly disposed or recycled.

(4)(A) The closed pit shall be filled with native materials and covered with topsoil at depths consistent with adjoining on-site areas, with the contour mounded or sloped to discourage erosion and restored as close to the original contours as is practicable.

(B) Topsoil and native materials removed during pit construction may be preserved and used during closure.

(5) The oil and grease content of the material to be buried in situ shall be less than three percent (3%) by dry weight.

(6)(A) The pit and applicable portion of the drill pad not utilized for production purposes shall be returned to grade, reclaimed, and seeded within a reasonable amount of time not to exceed one hundred eighty (180) days after the drilling or workover rig is removed from the site, or in the case of a multiple well drill pad, within one hundred eighty (180) days after the drilling or workover rig utilized for the last well to be drilled from the drill pad is removed, during which period the reserve pit shall be maintained in accordance with the provisions of this section.

(B) An extension of the time to close the pit may be granted upon approval of both the Oil and Gas Commission and the division.

(C)(i) Vegetative coverage of seventy-five percent (75%), or equivalent to the surrounding landscape, whichever is less, shall be obtained within six (6) months of pit closure.

(ii) Until vegetation is established, the operator is responsible for maintaining a stormwater erosion and sediment control plan.

(7)(A) The operator shall submit the notice of pit closure to the Oil and Gas Commission signed by the operator within thirty (30) days after pit closure has been completed.

(B) The Oil and Gas Commission shall forward a copy to the division.

(i) Fluid disposal and earthen pit closure requirements for oil-based drilling fluids.

(1)(A) Oil-based drilling fluids shall be:

(i) Removed from the pit and hauled to a permitted Class 1 (as defined by Arkansas Pollution Control and Ecology Commission, Solid Waste Management Rules, 8 CAR pt. 60) landfill for disposal;

(ii) Transferred to aboveground tanks for reuse at another well location; or

(iii) Disposed of with other methods or uses of oil-based drilling fluids as approved by the division.

(B) The operator shall inform the Oil and Gas Commission of the location of the disposal or transfer of the oil-based drilling fluids.

(2) If an oil-based drilling fluid other than diesel is used as the base, additional analytical or disposal requirements may be required, which shall require prior notification and approval by the division.

(3) Any synthetic liner used shall be removed to the fullest extent practicable and properly disposed or recycled.

(B) Topsoil and native materials removed during pit construction may be preserved and used during closure.

(5)(A) The area shall be returned to grade, reclaimed, and seeded within a reasonable amount of time not to exceed one hundred eighty (180) days after the drilling rig is removed from the site.

(B)(i) Vegetative coverage of seventy-five percent (75%), or equivalent to the surrounding landscape, whichever is less, shall be obtained within six (6) months of closure.

(ii) Until vegetation is established, the operator is responsible for maintaining a stormwater erosion and sediment control plan.

(6)(A) The operator shall submit the notice of pit closure to the Oil and Gas Commission signed by the operator within thirty (30) days after pit closure has been completed.

(B) The Oil and Gas Commission shall forward a copy to the division.

(j) Requirements for workover pits, emergency pits, and test pits.

(1) No produced water, workover flowback water, waste oil, or any other nonhazardous oilfield wastes (NOW) shall be placed in a workover, emergency, or test pit, unless the pit is lined in accordance with subdivision (f)(2)(B) of this section, above.

(2)(A) All workover, emergency, or test pits shall be closed within thirty (30) days after the associated workover, emergency, or test ceases.

(B) Any workover, emergency, or test pit shall be closed in accordance with the requirements of subsection (h) of this section, above.

(k) Other drilling mud systems not specifically authorized by this section shall require prior notification and approval by the:

(1) Director of Production and Conservation; and

(2) Director of the Division of Environmental Quality.

(l) Stormwater erosion and sediment controls.

(1)(A) The operator shall prepare a stormwater erosion and sediment control plan for the well site covered by this section.

(B) The plan shall be prepared in accordance with proven and accepted engineering practices.

(C) The plan shall describe and ensure the implementation of both erosion and sediment control practices which are to be used to reduce pollutants in stormwater discharges associated with the well pad and access roads to minimize erosion and reduce the sediments which may enter waters of the state and assure compliance with any applicable water quality standards (WQS).

(D) Facilities shall implement the provisions of the plan required under this section.

(E) The operator shall provide upon request by the division or Oil and Gas Commission a copy of the stormwater erosion and sediment control plan.

(2) In lieu of a stormwater erosion and sediment control plan as required above, the operator may use a guidance document that provides operators the appropriate erosion and sediment controls based upon geographic region, terrain, and distance to adjacent waterbodies previously submitted and approved by the division.

(3)(A) Any facility that potentially discharges stormwater runoff to a waterbody listed for siltation pursuant to Section 303(d) of the Clean Water Act of 1972, 33 U.S.C. § 1313(d), or an ERW, ESW, or NSW shall have a site specific stormwater erosion and sediment control plan prepared and certified by a registered professional engineer, and such plan shall incorporate best management practices to provide reductions of the listed pollutants to the extent reasonably feasible.

(B) The 303(d) list, and the location of ERW, ESW, and NSW waters are available from the division’s website at the following address: http://www.adeq.state.ar.us/water/.

History

Codification Notes: “NPDES” means National Pollutant Discharge Elimination System.This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: Original Rule Repealed October 15, 2006; New Rule Effective October 28, 2010 – Implementation October 1, 2011; amended April 1, 2012; amended November 19, 2018)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-216 Wellhead fittings {#sec-15-car-275-216 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-216}

15 CAR § 275-216. Wellhead fittings.

Christmas tree fittings or wellhead connections shall have a working pressure or a test pressure in keeping with the expected depth of the well.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-217 Requirements for well completion utilizing fracture stimulation {#sec-15-car-275-217 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-217}

15 CAR § 275-217. Requirements for well completion utilizing fracture stimulation.

(a) Definitions. As used in this section:

(1) “Additive” means any substance or combination of substances, including proppant, having a specified purpose that is combined with a hydraulic fracturing fluid;

(2) “Chemical Abstract Service” or “CAS” means the chemical registry that is the authoritative collection of disclosed chemical substance information;

(3) “Chemical constituent” means a discrete chemical with its own specific name or identity (such as, but not necessarily, a CAS number) that is contained in an additive;

(4) “Chemical family” means a group of elements in the period table of elements or, more commonly, compounds that share certain physical and chemical characteristics and have a common name;

(5) “DEQ” means the Division of Environmental Quality;

(6) “Hydraulic fracturing fluid” means the base fluid type utilized in a particular hydraulic fracturing treatment;

(7) “Hydraulic fracturing treatment” means stimulating a well by the application of hydraulic fracturing fluids and additives with force in order to create artificial fractures in the formation for the purpose of improving the capacity to produce hydrocarbons;

(8) “OGC” means the Oil and Gas Commission; and

(9) “RCRA” means Resource Conservation and Recovery Act, 42 U.S.C. § 6901 et seq.

(b) The provisions of this section shall apply to all new horizontal wells and all vertical wells:

(1) In which the amount of hydraulic fracturing fluid used during the hydraulic fracturing treatment of the well exceeds ten thousand (10,000) barrels hydraulic fracturing fluid; and

(2) For which an initial drilling permit was issued on or after January 15, 2011.

(c)(1) Persons applying for a permit to drill shall indicate on the initial drilling application the intent to perform hydraulic fracturing treatment operations and provide the information required in accordance with subsection (d) of this section, below.

(2) If the intent to fracture stimulate a well was not provided at the time of the initial drilling application, a permit holder desiring to perform hydraulic fracturing treatment operations shall send the information required in accordance with subsection (d) of this section, below, via email, fax, or mail to the Oil and Gas Commission office where the initial drilling permit was issued, prior to commencement of hydraulic fracturing treatment operations.

(d) The application described in subsection (c) of this section, above, shall include:

(1) The following information on the proposed casing program, demonstrating that the well will have steel alloy casing designed to withstand the anticipated maximum pressures to which the casing will be subjected in the well:

(A) Whether the well will be a:

(i) Vertical well;

(ii) Directional well; or

(iii) Horizontal well;

(B) The estimated true vertical and measured production casing setting depths; and

(2) The following information demonstrating that the well will have sufficient cement volume and integrity to prohibit movement of fracture fluids up-hole into the various casing or well bore annuli:

(A) The proposed cement formulation’s minimum compressive strength; and

(B) The estimated top of cement for the production casing string; and

(3)(A) The anticipated surface treating pressure range for the proposed hydraulic fracturing treatment program.

(B) The production casing described in subdivision (d)(1) of this section, above, shall be sufficient to contain the maximum anticipated treating pressure of the hydraulic fracturing treatment, which shall not exceed eighty percent (80%) of the minimum internal yield pressure for such production casing.

(e)(1) Surface casing in the well in which the proposed hydraulic fracturing treatment will occur shall:

(A) Be set and cemented to the surface to a depth in accordance with 15 CAR § 275-213; and

(B) Have sufficient internal yield pressure to withstand the anticipated maximum pressures to which the casing will be subjected in the well.

(2) If during the drilling of the surface portion of the well, and prior to setting surface casing, a freshwater flow is encountered, or the permit holder gains knowledge that fresh water will be encountered from a deeper zone than was specified on the permit to drill, surface casing shall be set and cemented at least one hundred feet (100’) below the deepest encountered freshwater zone.

(f)(1) If during the setting and cementing of production and/or any intermediate casings, the cement program does not occur as submitted in accordance with this part and would cause a reasonably prudent permit holder to question the integrity of the cementing program with respect to isolating the zone of hydraulic fracturing treatment from movement of fracture fluids up-hole into the various casing or well bore annuli, the permit holder shall immediately notify the Director of Production and Conservation or his or her designee in writing as soon as practicable, but not more than twenty-four (24) hours after the event.

(2) In reviewing the report, the director or his or her designee may require a bond log or other cement evaluation tool to document cement integrity and require additional cementing operations or other appropriate well workover efforts necessary to correct any cement deficiencies prior to initiating any hydraulic fracturing treatments in the well.

(g)(1) The permit holder shall notify the director or his or her designee via email, fax, or other approved method, a minimum of forty-eight (48) hours prior to commencement of a hydraulic fracturing treatment on a well.

(2) If the permit holder cannot provide notice a minimum of forty-eight (48) hours’ notice prior to commencement, the permit holder shall provide a written explanation as to why the notice could not be provided, and the permit holder shall provide notice in the manner described above as soon as the permit holder is aware that a hydraulic fracturing treatment has been scheduled.

(h)(1) The permit holder shall monitor all casing annuli that would be diagnostic as to a potential loss of well bore integrity during the hydraulic fracturing treatment.

(2) The permit holder shall establish methods to timely relieve any excessive pressures to avoid the loss of surface casing integrity.

(i)(1) The permit holder must provide written notice to the director or his or her designee of:

(A) Any change in surface casing annulus pressure that would indicate movement of fluids into the annulus; or

(B) A pressure that exceeds the rated minimum internal yield pressure on any casing string in communication with the hydraulic fracturing treatment.

(2) This written notice shall be delivered as soon as possible after the event, but not more than twenty-four (24) hours after the event.

(3)(A) Following notification and any request for additional information, the director or his or her designee may request additional documentation or well tests to determine if the hydraulic fracturing treatment potentially endangered any freshwater zones.

(B) The director or his or her designee may require appropriate additional cementing operations or other well workover efforts to correct any well failure.

(C) Pending completion of required operations or efforts, the director or his or her designee may order the cessation of further hydraulic fracturing treatment and/or other well operations.

(D) The director shall report any such incident to the commission at its next regularly scheduled hearing, and the commission may take such further action as it deems necessary and appropriate under the circumstances.

(j)(1) All nonexempt RCRA materials and fluids used on-site in the hydraulic fracturing treatment shall be handled and stored in accordance with Division of Environmental Quality requirements, and any spills of these materials and fluids on-site or off-site shall be reported to the division in accordance with applicable division requirements.

(2) All RCRA exempt materials and fluids used on-site in the hydraulic fracturing treatment shall be contained in leak-free tanks or other containment vessels.

(3) Any on-site spill of these materials or fluids shall be immediately contained, remediation efforts shall be commenced as soon as practical, and the incident shall be reported to the director or his or her designee within twenty-four (24) hours.

(k) All hydraulic fracturing treatment flowback fluids shall be handled, transported, stored, disposed, or recycled for reuse in accordance with the applicable provisions of:

(1) 15 CAR § 275-215;

(2) 15 CAR § 275-503; and

(3) 15 CAR §§ 275-801 – 275-803.

(l)(1) Following completion of the hydraulic fracturing treatment, the permit holder shall, for purposes of disclosure, report detailed information to the director or his or her designee of the hydraulic fracturing treatment in the manner customarily reported or presented to the permit holder, within the time period specified in 15 CAR § 275-205, as follows:

(A) The maximum pump pressure measured at the surface during each stage of the hydraulic fracturing treatment;

(B) The types and volumes of the hydraulic fracturing fluid and proppant used for each stage of the hydraulic fracturing treatment;

(C) The calculated fracture height as designed to be achieved during the hydraulic fracturing treatment and the estimated TVD to the top of the fracture;

(D) A list of all additives used during the hydraulic fracturing treatment specified by general type, such as:

(i) Acid;

(ii) Biocide;

(iii) Breaker;

(iv) Corrosion inhibitor;

(v) Crosslinker;

(vi) Demulsifier;

(vii) Friction reducer;

(viii) Gel;

(ix) Iron control;

(x) Oxygen scavenger;

(xi) pH adjusting agent;

(xii) Scale inhibitor;

(xiii) Proppant; and

(xiv) Surfactant;

(E)(i) The names of all specific additives for each additive type, specified in subdivision (l)(4) of this section, above, utilized during the hydraulic fracturing treatment and the actual rate or concentration for each such additive expressed as pounds per thousand (1,000) gallons or gallons per thousand (1,000) gallons.

(ii) Additionally, the additives are to be expressed as a percent by volume of the total hydraulic fracturing fluids and additives;

(F) The permit holder shall supply field service company tickets (excluding pricing) and reports regarding the hydraulic fracturing treatment as used in the normal course of business to satisfy some or all of the foregoing information requirements;

(G) The permit holder shall supply all information received from the person performing the hydraulic fracturing treatment specified in subdivision (m)(4) of this section, below; and

(H)(i) If the permit holder causes any additives to be utilized during the hydraulic fracturing treatment not otherwise disclosed by the person performing the hydraulic fracturing treatment, the permit holder shall disclose a list of all chemical constituents and associated CAS numbers contained in all such additives.

(ii) Provided, however, in those limited situations where the specific identity of any such chemical constituent and associated CAS number is entitled to be withheld as a trade secret under the criteria set forth in 42 U.S.C. § 11042(a)(2), the permit holder shall:

(a) Submit to the director a claim of entitlement to have the identity of such chemical constituent withheld as a trade secret; and

(b)(1) Provide the director with the chemical family associated with such chemical constituent.

(2) The identity of any chemical constituent that qualifies as a trade secret under the criteria set forth in 42 U.S.C. § 11042(a)(2) shall be held confidential by the director.

(2)(A) Nothing in subdivision (l)(8) of this section, above, shall authorize any person to withhold information which is required by state or federal law to be provided to a:

(i) Healthcare professional;

(ii) Doctor; or

(iii) Nurse.

(B) All information required by a healthcare professional, a doctor, or a nurse shall be supplied immediately upon request by the person performing the hydraulic fracturing treatment directly to the requesting healthcare professional, doctor, or nurse, including the percent by volume of the chemical constituents and associated CAS numbers of the total hydraulic fracturing fluids and additives.

(m) Any person performing hydraulic fracturing treatments within the State of Arkansas shall:

(1) Be authorized to do business in the State of Arkansas;

(2) Be required to file organization reports in accordance with 15 CAR § 275-212, and include the length of time the entity has been in the business of performing hydraulic fracturing treatments;

(3) Disclose to the director or his or her designee and maintain separate master lists of:

(A) All hydraulic fracturing fluids to be utilized during any hydraulic fracturing treatment within the State of Arkansas;

(B) All additives to be utilized during any hydraulic fracturing treatment within the State of Arkansas; and

(C)(i) All chemical constituents and associated CAS numbers to be utilized in any hydraulic fracturing treatment within the State of Arkansas.

(a) Submit to the director a claim of entitlement to have the identity of such chemical constituent withheld as a trade secret; and

(b)(1) Provide the director with the chemical family associated with such chemical constituent.

(2) The identity of any chemical constituent that qualifies as a trade secret under the criteria set forth in 42 U.S.C. § 11042(a)(2) shall be held confidential by the director; and

(4) Provide to the permit holder for each well that such person performs a hydraulic fracturing treatment, lists of:

(A) The hydraulic fracturing fluids utilized during the hydraulic fracturing treatment;

(B)(i) The additives utilized during the hydraulic fracturing treatment, and the actual rate or concentration for each such additive utilized, expressed as pounds per thousand gallons or gallons per thousand gallons.

(ii) Additionally, the additives are to be expressed as percent by volume of the total hydraulic fracturing fluids and additives, so that the permit holder may comply with its obligations under subsection (l) of this section, above; and

(C) All chemical constituents and associated CAS numbers utilized during the hydraulic fracturing treatment, unless the specific identity of any such chemical constituent and associated CAS number is entitled to be withheld as a trade secret in accordance with subdivision (m)(3)(C) of this section, above.

(n)(1) Nothing in subdivision (m)(3)(C) or subdivision (l)(9) of this section, above, shall authorize any person to withhold information which is required by state or federal law to be provided to a:

(A) Healthcare professional;

(B) Doctor; or

(2) All information required by a healthcare professional, a doctor, or a nurse shall be supplied immediately upon request by the person performing the hydraulic fracturing treatment directly to the requesting healthcare professional, doctor, or nurse, including the percent by volume of the chemical constituents and associated CAS numbers of the total hydraulic fracturing fluids and additives.

(o) No permit holder shall utilize the services of another person to perform a hydraulic fracturing treatment unless the person performing a hydraulic fracturing treatment is in compliance with subsection (m) of this section, above.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: Original Rule Repealed October 15, 2006; New Rule Effective January 15, 2011; Amended February 08, 2013; Amended July 15, 2017)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-218 Tubing {#sec-15-car-275-218 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-218}

15 CAR § 275-218. Tubing.

(a)(1) All oil wells shall be equipped with and produced through tubing.

(2) Bottom of tubing on flowing wells shall not be higher than top of producing interval.

(3) If tubing is perforated, the perforations shall not extend above the top of the producing interval.

(b)(1) All dry gas wells are not required to produce through tubing, provided surface casing has been set in the well in accordance with applicable rules.

(2) If multiple gas zones are produced in the well, authority to commingle in accordance with 15 CAR § 275-407 shall be required.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book; amended October 15, 2006)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-219 General lease operating requirements {#sec-15-car-275-219 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-219}

15 CAR § 275-219. General lease operating requirements.

(a) Definitions for purposes of this section:

(1) “Crude oil tank battery” means crude oil storage tanks and other vessels commonly used in the production and temporary storage of crude oil;

(2) “DEQ” means the Division of Environmental Quality;

(3) “Director” means the Oil and Gas Commission Director of Production and Conservation;

(4) “EPA” means the United States Environmental Protection Agency;

(5) “Gas well produced fluids storage tanks” means tanks or other vessels commonly used for the temporary storage of fluids produced with natural gas prior to disposal;

(6) “Lease” means a tract of land under agreement by an owner or person for the purpose of producing oil and/or gas and allocating that production for himself or herself or the owners of the oil and gas rights under that tract of land;

(7) “Permit holder” means the operator or person who is duly authorized to develop a lease or unit as owner or through agreement and has the right to drill and produce from any field or reservoir and to appropriate the production for himself or herself or others;

(8) “Produced fluids” means those fluids produced or generated during the crude oil production and separation process and shall include:

(A) Crude oil, crude oil bottom sediment; and

(B) All waters regardless of chloride content associated with production of oil and/or gas;

(9) “Oil well produced fluids storage tanks” means tanks or other vessels commonly used for the temporary storage of fluids produced with crude oil prior to disposal;

(10) “Oil well produced fluids storage tanks” means tanks or other vessels commonly used for the temporary storage of fluids produced with crude oil prior to disposal;

(11) “RCRA” means Subtitle C of the Federal Resource Conservation Recovery Act of 1976, Pub. L. No. 94-580; and

(12) “USDW” means Underground Source of Drinking Water which is defined as an aquifer or its portion which:

(A) Supplies any public water system or contains a sufficient quantity of groundwater to supply a public water system and currently supplies drinking water for human consumption or contains fewer than ten thousand milligrams per liter (10,000 mg/l) total dissolved solids; and

(B) Which is not an exempted aquifer (see Title 40 of the Code of Federal Regulations).

(b) Well identification.

(1)(A) Each oil and/or gas well shall have a legible sign placed at the well showing the permit holder and the well name and number as shown on the permit as listed in the Oil and Gas Commission records.

(B) If the lease is a single well lease, the well sign may be placed at the associated tank battery or lease entrance.

(2)(A) Every entrance from a public road to north Arkansas gas well sites shall have a legible sign placed at that entrance.

(B) The sign shall show:

(i) The name of the permit holder;

(ii) A list of all wells accessed by that entrance;

(iii) The section, township, and range; and

(iv) A telephone number at which the permit holder or his or her authorized agent can be reached during an emergency.

(3) For any newly drilled well, the required sign shall be posted within forty-five (45) days after cessation of drilling operations.

(4)(A) Any changes or corrections in the well information required to be posted in accordance with this section shall be made to the well signs within sixty (60) days after the change occurs, or in the case of a transfer of well ownership, within sixty (60) days after the effective date of the transfer in the Oil and Gas Commission records.

(B) All prior signs, if not correct, shall be removed.

(1)(A) All existing and newly constructed crude oil tank batteries and oil well produced fluids storage tanks shall be registered with the Oil and Gas Commission and assigned an Oil and Gas Commission registration number.

(B) Registration shall be reported to the Oil and Gas Commission utilizing information as reported on the existing Oil and Gas Commission Form 6 Monthly Producers Report.

(2) All crude oil tank battery and oil well produced fluids storage tank registrations shall be transferred, at the time of associated well transfers, utilizing the approved notice of well transfer forms filed with the Oil and Gas Commission.

(3)(A) Each crude oil tank battery and oil well produced fluids storage tank shall have a legible sign in a conspicuous place on or near the crude oil storage tank.

(B) The sign shall show:

(i) The name of the permit holder who holds the Oil and Gas Commission permit to operate the lease or unit;

(ii) The lease name;

(iii) The section, township, and range; and

(iv) A telephone number at which the permit holder or his or her authorized agent can be reached during an emergency.

(4)(A) All crude oil tank batteries and oil well produced fluids storage tanks shall be surrounded by containment dikes or other containment structures as may be appropriate under the circumstances, as approved by the Director of Production and Conservation.

(B) All containment dikes or other approved structures shall be constructed or installed in accordance with subsection (e) of this section, below.

(5) All crude oil tank batteries and oil well produced fluids storage tanks constructed after the effective date of this section shall not be located within:

(A)(i) Two hundred feet (200’) of an existing occupied habitable dwelling, unless the current owner of the structure has provided a written waiver consenting to the construction closer than two hundred feet (200’), in which case the tank battery shall be completely fenced to prevent unauthorized access.

(ii) However, in no event may a tank battery be constructed closer than one hundred feet (100’) to an existing habitable dwelling;

(B) Three hundred feet (300’) of a school, hospital, or other type of public use building as defined in Arkansas Fire Prevention Code § 3406.3.1.3.1, 12 CAR pt. 14; or

(C) Three hundred feet (300’) of a stream or river designated as an extraordinary resource water (ERW), natural and scenic waterways, or ecological sensitive waterbodies as defined by Arkansas Pollution Control and Ecology Commission, 8 CAR pt. 21, or within two hundred feet (200’) of other streams, waterways, rivers, ponds, lakes, wetlands (unless approved by other appropriate governmental agencies), or other bodies of water (as indicated by a blueline designation on a seven and one-half (7.5) minute United States Geological Survey topographic map), unless the permit holder utilizes additional containment measures other than the required containment specified in subsection (e) of this section, below, as approved by the director.

(6) All crude oil tank batteries and oil well produced fluids storage tanks or any part of such tanks shall not be buried below the ground surface.

(7) All crude oil tank batteries and oil well produced fluids storage tanks shall be maintained in a leak-free condition.

(8) All open top tanks shall be covered with bird netting or other system designed to keep birds and flying mammals from landing in the tank.

(d) Gas well produced fluids storage tanks.

(1) Tanks or any part of such tanks shall not be buried below the ground surface.

(2) All tanks shall be maintained in a leak-free condition.

(3) All open top tanks shall be covered with bird netting or other system designed to keep birds and flying mammals from landing in the tank.

(4) Tanks constructed after the effective date of this section shall not be located within:

(ii) However, in no event may a tank battery be constructed closer than one hundred feet (100’) to an existing habitable dwelling;

(B) Three hundred feet (300’) of a school, hospital, or other type of public use building as defined in Arkansas Fire Prevention Code Section 3406.3.1.3.1, 12 CAR pt. 14; or

(5)(A) All tanks containing produced fluids or equipped to receive produced fluids shall be surrounded by containment dikes or other containment structures as may be appropriate under the circumstances, as approved by the director.

(B) All containment dikes or other approved structures shall be constructed or installed in accordance with subsection (e) of this section, below.

(e) Containment dikes or other containment structures.

(1) All crude oil tank batteries, oil well produced fluids storage tanks, and gas well produced fluids storage tanks shall be surrounded by containment dikes or such other structure as may be appropriate under the circumstances as approved by the director to prevent waste, protect life, health, or property, unless an exception is granted by the Oil and Gas Commission following notice and hearing.

(2) Required containment dikes or other approved structures shall be designed to have a capacity of at least one and one-half (1 1/2) times the largest tank the containment dike or approved structure surrounds.

(3) The natural or human-made material utilized for the construction of the required containment dikes or other approved structures and the natural or human-made material used to line the bottom of the containment area shall be sufficiently impervious so as to contain fluids and resist erosion.

(4) Vegetation on the top and outside surface of containment structures shall be properly maintained so as to not pose a fire hazard.

(5)(A) The area within the containment dike or other approved containment structure shall be kept free of excessive vegetation, stormwater, produced fluids, other oil and gas field related debris, general trash, or any flammable material.

(B) Drain lines installed through the firewall, for the purpose of draining stormwater, shall have a valve installed which shall remain closed and capped when not in use.

(C) Any fluids collected, spilled, or discharged within such containment structures shall be removed as soon as practical, using the following proper disposal methods:

(i) Stormwater, which has not been mixed with nonexempt RCRA waste as defined by the United States Environmental Protection Agency, may be drained from the containment structure provided the following conditions are met:

(a) The chloride content shall not exceed applicable state water quality standards;

(b) There must be no visible evidence of hydrocarbons or hydrocarbon sheen present;

(d) A representative of the permit holder must be present during discharge, unless otherwise approved by the director; and

(e)(1) The permit holder shall maintain a record of each stormwater discharge occurring in the previous six-month period, and which shall be available for review upon request by Oil and Gas Commission staff.

(2) The record shall indicate the location, quantity, chloride content, presence of any hydrocarbons (sheen), and date of discharge;

(ii) Produced fluids which have not been mixed with nonexempt RCRA waste as defined by the United States Environmental Protection Agency may be recycled through the production equipment or removed from the containment structure and disposed in a properly permitted Class II UIC well;

(iii) All stormwater and produced fluids which have been mixed with nonexempt RCRA waste as defined by the United States Environmental Protection Agency shall be removed and disposed in accordance with applicable Arkansas Pollution Control and Ecology Commission rules, as administered by the Division of Environmental Quality; and

(iv) Crude oil bottom sediments (BS&W) may be:

(a) Applied on oil field lease roads under the following conditions:

(1) Application shall be in such a manner as to avoid runoff onto immediately adjacent lands or into waters of the state;

(2) Immediately following completion of the application, all liquid fractions shall be immediately incorporated into the road bed with no visible free-standing oil;

(3) No lease road shall be oiled more than twice a year;

(4) No lease road shall be oiled during precipitation events; and

(5) The applied BS&W shall not have a produced water content greater than ten percent (10%) free water by volume; or

(b) Injected into an inactive oil and gas production well:

(1) Which has been equipped with tubing and packer, for the purpose of said injection, the packer to be set within the production casing at least fifty feet (50’) below the top of the production casing cement, but no less than five hundred feet (500’) below the base of the deepest USDW;

(2) Injection of the BS&W shall not exceed forty-five (45) days, after which time the well shall be immediately plugged in accordance with 15 CAR § 275-208; and

(3) If the director determines through field observations that the injection activities are endangering the USDW, the injection activities shall cease until the condition is corrected.

(6) Any residual produced fluids remaining within the containment dike, after removal, as required in subdivision (e)(5) of this section, above, shall be remediated in place in accordance with 15 CAR § 275-222.

(7) Any spill, leak, or discharge of produced fluids escaping from a containment dike shall be reported and remediated in accordance with 15 CAR § 275-222.

(8) When a crude oil tank battery, oil well produced fluids storage tank, gas well produced fluids storage tank, or a gas well separator is removed, the permit holder shall:

(A) Remove all aboveground piping and flowlines coming into said tanks or separator;

(B) Cap all belowground piping and flowlines;

(D) Remove from site all nonsoil containment structure construction material; and

(E) Remediate all hydrocarbon contaminated soil at tank or separator site in accordance with 15 CAR § 275-222.

(f) Liquid hydrocarbon flowlines and produced fluid flowlines.

(1)(A) All flowlines used in the production of liquid hydrocarbons constructed after the effective date of this section shall be buried at least twenty-four inches (24”) below the ground surface.

(B) Flowlines may be exempt from these burial requirements upon approval of the director if, in the following circumstances, the:

(i) Topographical features, land uses, or ground conditions prevent the efficient burial of flowlines;

(ii) Suspected presence of numerous old abandoned flowlines in old producing fields renders the burial of new lines impractical, or which will significantly increase the likelihood of causing the discharge of crude oil from the old lines;

(iii) Terms of the oil and gas lease or surface owner agreement prohibit the burial of flowlines;

(iv) Flowlines are installed or placed within the lease road right-of-way; or

(v) Flowlines from the well to the tank battery are entirely within the confines of the original drilling location.

(2) All flowlines which cross and are not buried under natural drainage features such as creeks, streams, rivers, or intermittent streams or ravines shall be constructed in such fashion as to bridge the drainage feature to protect the flowlines from damage due to lack of adequate support, resulting in potential discharge and violation of the state water quality standards.

(3) The director shall have the authority to require active flowlines existing on the effective date of this section to be replaced, buried, or constructed in accordance with subdivision (f)(2) of this section, above, or to require the visible aboveground inactive or abandoned portions of those abandoned flowlines to be removed and the open ends sealed if the director finds, based on field observation, that the flowlines constitute a hazard to public safety or can reasonably be expected to cause damage to the environment through leaks, spills, or discharges.

(4)(A) No flowlines transporting produced water shall have an outlet valve installed for the purpose of discharging produced water between the place or well of origin and the authorized storage or disposal point.

(B) A specialized valve, installed for the purpose of venting trapped air, following flowline maintenance is permissible.

(5) Any spill, leak, or discharge from a flowline shall be reported and remediated in accordance with 15 CAR § 275-222.

(g) Natural gas production lines and gathering lines shall be installed and operated in accordance with 15 CAR § 275-406 or other applicable Oil and Gas Commission rules.

(h) Power lines.

(1) All power lines installed after the effective date of this section shall be installed in such a manner as to prevent contact by vehicle or pedestrian travel.

(2) The director shall have the authority to require power lines existing on the effective date of this section to be in compliance with subdivision (h)(1) of this section, above, if the director finds, based on field observation, that the power lines constitute a hazard to public safety.

(i) Equipment use and storage.

(1) All wellhead areas shall be kept free of excessive vegetation.

(2) All production equipment, including but not limited to separators, heater treaters, piping, compressors, injection pumps, and chemical containers, shall be kept free of vegetation and maintained at all times in a safe and good working condition.

(3)(A) Used refined oil from any production equipment such as pumpjacks, injection pumps, and compressors shall not be improperly disposed or placed in storage tanks containing produced water.

(B) All used refined oil shall be disposed in accordance with Arkansas Pollution Control and Ecology Commission, 8 CAR pt. 81, Section 279.

(4) Excess usable or operable production equipment, not integrally related to production activities on the lease, established drilling unit, or other unitized production area shall not be stored on any surface property unless written consent from the current surface owner where the production equipment is located has been granted to the permit holder to store such equipment, unless the equipment has been designated by the permit holder to be used in the future on that lease, established drilling unit, or other unitized production area, and the equipment and storage area, which shall be limited to an area in close proximity to existing well sites or production areas, are maintained and kept free of excessive vegetation.

(5)(A) Other trash and debris, including, but not limited to, abandoned, unusable, or unrepairable junk tanks, treaters, tubulars, injection pumps, pump jacks, concrete, aboveground piping and flowlines, and any other general junk equipment or machinery shall not be stored on any surface property except that owned by the permit holder.

(B) Removed trash and debris shall be disposed in accordance with applicable Division of Environmental Quality or other state agency rules.

(j) Production pits.

(1) "Production pit", as used in this section, means an earthen surface impoundment, whether a human-made excavation or a diked area, which was or currently is used for temporary storage of produced fluids prior to disposal.

(2) Construction of production pits, other than those pits previously authorized by Oil and Gas Commission orders are prohibited.

(3) All other production pits in existence as of the effective date of this section shall cease to be used on the effective date of this section and closed within ninety (90) days after the effective date of this section in a manner prescribed by the Oil and Gas Commission and in accordance with all applicable state laws and rules, unless exempted in accordance with subdivision (j)(4) of this section, below.

(4) Any production pit in existence as of the effective date of this section may not be subject to closure in accordance with subdivision (j)(3) of this section, above, if:

(A) The pit is no longer used for temporary storage of produced fluids;

(B) The water quality in the pit is less than one thousand five hundred (1,500) TDS with no visible sheen of oil;

(C) A written, notarized authorization from the current surface owner has been received by the director requesting the pit not be closed and demonstrating an acceptable alternative use for the pit; and

(D) In determining not to require the pit be closed, the director shall review the:

(i) Current location of the pit relative to any ongoing production operations in the area; and

(ii) Proposed alternative use relative to public health and safety considerations and potential use for agricultural, recreational, or wildlife habitat purposes.

(5) If the director determines, based on a review of the information submitted by the operator and surface owner, the pit is not exempted, the pit shall be closed within six (6) months by the operator in accordance with subdivision (j)(3) of this section, above.

(k) Leaking permitted well.

(1) Where any oil and gas reservoir fluids or saltwaters or other produced fluids are potentially leaking into the USDW as determined by geologic and field investigation, or are leaking onto the surface through a permitted well transferred to the permit holder, the permitted well shall be plugged by the permit holder.

(2) Pending plugging of the well, all injection wells within a one-fourth-mile radius of the leaking drill hole shall be shut in until the well is plugged.

(l) Leaking previously plugged well.

(1) Where any oil and gas reservoir fluids or saltwaters are potentially leaking into the USDW or to the surface as determined by geologic and field investigation through a well plugged under applicable Oil and Gas Commission rules, the well shall be replugged by the original permit holder responsible for plugging the leaking well.

(2) If the original permit holder is no longer in existence or cannot be located, the well shall be eligible for plugging through the Abandoned and Orphaned Well Plugging Fund.

(3) Pending plugging of the well, all injection wells within a one-fourth-mile radius of the leaking well shall be shut in until the leaking well is plugged.

History

Codification Notes: “BS&W” means basic sediment and water."TDS" means total dissolved water.This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book; amended July 13, 2003; amended October, 14, 2007; amended August 17, 2008; amended June 16, 2019; amended December 21, 2020)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-220 Deviation tests {#sec-15-car-275-220 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-220}

15 CAR § 275-220. Deviation tests.

(a)(1) The maximum point at which a well penetrates the producing formation shall not unreasonably vary from the vertical drawn from the center of the hole at the surface.

(2) Deviations in excess of the following shall be deemed to be unreasonable, more than three degrees (3°) from the vertical drawn from the center of the hole at the surface.

(b) The Oil and Gas Commission shall have the right to make, or to require the operator to make, a directional survey of the hole under the following circumstances:

(1) In all cases where the operator has proposed to deliberately drill a directional well from an exceptional surface location and/or to an exceptional bottom hole location;

(2) Prior to a permit being issued, if an off-set operator requests a directional survey and agrees in writing to:

(A) Pay all costs and expenses of such survey;

(B) Assume liability for all risks associated with the survey; and

(C) Posts a bond in sufficient sum as determined by the commission as security against all costs and risks associated with the survey; or

(3)(A) At any time, by order of the commission, if the commission is first presented with substantial evidence that it is likely that the well was drilled other than at the location permitted or that the well has deviated in the direction of a unit boundary to a bottom location which would necessitate an increased penalty upon the well's production allowable.

(B) The commission shall have the continuing jurisdiction to assess the expense and risk of such survey between the operator and any opposing party.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book; amended July 13, 2003)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-221 Vacuum pumps prohibited {#sec-15-car-275-221 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-221}

15 CAR § 275-221. Vacuum pumps prohibited.

(a) The use of vacuum pumps or other devices for the purpose of putting a vacuum on any gas or oil-bearing stratum is prohibited except in fields using vacuum pumps on January 1, 1939, unless otherwise approved by the Oil and Commission or in accordance with subsection (b) of this section, below.

(b) Administrative approval. The Director of Production and Conservation or his or her designee is authorized to approve an application for administrative approval of the use of vacuum pumps or other devices for the purpose of putting a vacuum on any gas or oil-bearing stratum if the following conditions are met:

(1) The application provides proof that the field is practically depleted or the use of vacuum pumps or other devices for the purpose of putting a vacuum on any gas or oil-bearing stratum is otherwise necessary for the prevention of waste;

(2) The application includes detailed plat maps indicating current well locations in all included drilling units or leases in uncontrolled pools or fields;

(3) Notice has been given to all owners, as defined by Arkansas Code § 15-72-102(9) and no objections were received by the director in accordance with subdivision (b)(6) of this section, below;

(4) Each such application is submitted on a form prescribed by the director and includes the name and address of each owner as defined in Arkansas Code § 15-72-102(9), within each drilling unit in which applicant seeks approval to use the vacuum pump or other devices for the purpose of putting a vacuum on any gas or oil-bearing stratum;

(5) Concurrently with the filing of such application, the applicant shall send to each owner specified in subdivision (b)(4) of this section, above, a notice of the application filing and verify such mailing by affidavit, setting out the names and addresses of all owners as defined by Arkansas Code § 15-72-102(9), and the date of mailing;

(6)(A) Any owner, as defined by Arkansas Code § 15-72-102(9), noticed in accordance with subdivision (b)(5) of this section, above, shall have the right to object to the granting of such application within fifteen (15) days after the receipt of the application by the commission.

(B) Each objection must be made in writing and filed with the director or his or her designee.

(C) If a timely written objection is filed as herein provided, then the applicant shall be promptly furnished a copy and such application shall be denied.

(D) If the application is denied under this subsection, the applicant may file an application for hearing in accordance with 15 CAR §§ 275-101 and 275-102, and other applicable hearing procedures;

(7)(A) An application may be referred to the commission for determination when the director or his or her designee deems it necessary that the commission make such determination for the purpose of protecting the correlative rights of all parties, in order to prevent waste, or for any other reason.

(B) Promptly upon such determination, and not later than fifteen (15) days after receipt of the application, the director or his or her designee shall give the applicant written notice, citing the reason or reasons for referral to the full commission for determination, and the application shall be denied.

(C) If the application is denied under this subsection, the applicant may file an application for hearing in accordance with 15 CAR §§ 275-101 and 275-102, and other applicable hearing procedures; and

(8) If the director has not notified the applicant of the determination to refer the application to the commission within the fifteen-day period in accordance with the foregoing provisions, and if no objection is received at the office of the commission within the fifteen (15) days as provided for in subdivision (b)(6) of this section, the application shall be approved.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book; amended July 29, 2011)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-222 Notice of fire, breaks, or blowouts and remediation of associated spills of crude oil and produced water {#sec-15-car-275-222 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-222}

15 CAR § 275-222. Notice of fire, breaks, or blowouts and remediation of associated spills of crude oil and produced water.

(a) Definition for purposes of this section. “Permit holder” means the operator or person who:

(1) Is duly authorized to develop a lease or unit as owner or through agreement; and

(2) Has the right to:

(A) Drill and produce from any field or reservoir; and

(B) Appropriate the production for himself or herself or others.

(b) Notification.

(1) Any permit holder of an oil, gas, and brine production, UIC Class II, and Class V (brine disposal) well, or an owner or operator of tanks, storage tanks, or other receiving and storage receptacles into which crude oil is produced, received, or stored, or through which oil is transported in flowlines, shall immediately, but not more than twenty-four (24) hours later, notify the Oil and Gas Commission regional office where the event has occurred, by telephone or facsimile, concerning all fires, blowouts, spills, leaks, or discharges in excess of one (1) barrel of crude oil or five (5) barrels of produced water, which occur at these facilities.

(2)(A) All notices of fires, blowouts, spills, leaks, or discharges provided to the commission regional office shall include the name of the operator responsible and the location of the fire, blowout, spill, leak, or discharge by providing the:

(i) Section, township, and range; and

(ii) Property, lease, or unit name.

(B) Such report shall also specify what emergency steps have been taken or are in progress to remedy the situation reported.

(3) If the reported fire, blowout, spill, leak, or discharge results in a spill or discharge in excess of one (1) barrel of crude oil and/or five (5) barrels of produced water outside the containment, the permit holder shall also provide the following in the required written incident report, on a form prescribed by the Director of Production and Conservation:

(A) The amount of crude oil and produced water spilled or discharged;

(B) The areal extent of the spill or discharge;

(D) The proposed remediation efforts.

(4) Spills or discharges from interstate and intrastate pipeline (downstream from custody transfer), or from refined product pipelines are not covered by this section and are under the jurisdiction of the Division of Environmental Quality.

(5)(A) All crude oil and produced water spills or discharges, regardless of amount, which enter waters of the state as defined in Arkansas Code § 8-4-102, shall be reported immediately to the division.

(B) That portion of the spill which entered waters of the state shall be under the jurisdiction of the division for remediation and enforcement purposes.

(1) All crude oil spills that occur after the effective date of this section, regardless of amount, from wells, flowlines, tanks, pits, or containment dikes are subject to this section.

(2) The permit holder is required to initiate the following emergency response procedures for all crude oil spills immediately after a spill has occurred, but not more than twenty-four (24) hours after the spill:

(A) Contain spilled crude oil using earthen dikes, booms, and other containment measures to minimize the amount of area affected by the spill;

(B)(i) If a spill enters surface waters, the spill shall be contained with booms and/or underflow dams and removed as expeditiously as possible.

(ii) Further remediation requirements shall be determined by the division in accordance with subdivision (a)(5) of this section, above;

(D) Impounded free oil shall be picked up and put in lease storage tanks or removed from the site and recycled.

(3) Remaining oil on the land surface shall be removed using absorbent material, which shall be handled as follows:

(A) All nonorganic/nonbiodegradable absorbent materials shall be removed from the site and disposed of at a division permitted waste treatment or disposal facility or other disposal options as allowed by applicable state law or rule.

(B) On-site disposal of organic/biodegradable absorbent materials, such as straw and peat moss, may be disposed through land spreading over the area affected by the initial spill and remediated in accordance with subdivisions (c)(4)(A)(i) – (iv) of this section, below.

(4)(A) Contaminated soil area affected by a spill may be remediated in place and shall, within ten (10) days, at a minimum be:

(i) Fertilized with 13-13-13 fertilizer or an amount of other acceptable fertilizer sufficient to treat the soil with one-half pounds per square yard (0.5 lbs./yd²);

(ii)(a) Limed with sufficient agricultural grade lime over the affected area in order to maintain a pH of between six (6) and eight (8).

(b) If the pH of the soil/oil mixture is less than six (6), additional lime shall be incorporated to increase pH above six (6);

(iii) Tilled to a depth of at least four inches (4”) but no greater than twelve inches (12”) to create a soil and crude oil mixture that contains less than five percent (5%) total petroleum hydrocarbon (TPH) following the completion of the initial tilling;

(iv) Watered to maintain soil moisture sufficient to promote plant growth (if extremely dry soil conditions exist); and

(v) Stabilized to minimize erosion and runoff of stormwater to prevent violation of applicable water quality standards.

(B) If the soil in the affected area is frozen or previously saturated due to rain or snow melt prohibiting compliance with subdivision (c)(4)(A) of this section, above, the permit holder shall stabilize the area to prevent any surface runoff of crude oil from leaving the affected area until conditions permit compliance with subdivision (c)(4)(A) of this section, above.

(C) The soil affected by the spill must contain less than one percent (1%) TPH within twelve (12) months after the date of the spill.

(D) The director may require additional remediation action to be taken by the operator, which may include:

(i) Flushing of the area with freshwater (which shall be collected and disposed in a UIC Class II well);

(ii) The addition of organic material (e.g., peat moss, straw);

(iii) Chemical treatment;

(iv) Additional disking of the soil; or

(v) Soil and absorbent material removal if the soil and/or absorbent material within the spill area cannot meet the TPH standard specified in subdivision (c)(4)(A)(iii) of this section, above.

(E) Contaminated soils removed from the site for off-site disposal shall be disposed of at a division permitted landfill permitted to receive such waste, or other division permitted surface waste treatment or disposal facility, or as required by applicable state law or rule.

(5) If a spill enters a public road ditch, visible crude oil-contaminated soil shall be removed from the roadside ditch and:

(A) Removed from the site in accordance with subdivision (c)(4)(E) of this section, above; or

(B) Incorporated into the nonroad ditch area of the spill and remediated in accordance with subdivision (c)(4)(A) of this section, above.

(6)(A) The permit holder shall be required to submit on request, or within fifteen (15) days after the spill occurred, on a form prescribed by the director, the following information:

(i) A topographic map showing the areal extent of the spill and the proximity of surface waters;

(ii) The type of soil and current land use;

(iii) The TPH content in the spill area; and

(iv) Explanation of the cause of the spill, and planned efforts to prevent and minimize the effects of future spills at the site.

(B) Additional reports are required each ninety (90) days until the spill remediation is completed and approved by the director.

(7) The commission, after notice and hearing, shall have the authority to amend the above remediation methodology or approve alternative remediation methodologies if those methods achieve the same or higher standard of spill remediation.

(d) Produced water spill remediation requirements.

(1) All spills of produced water, which occur after the effective date of this section, from wells, flowlines, pits, tanks, or containment dikes, shall immediately, but not more than twenty-four (24) hours, be contained using earthen dikes and other containment measures to minimize the amount of area affected by the spill.

(2) All impounded produced water shall be picked up and removed from the site for disposal into an approved Class II UIC well, or recycled through the permit holder’s production process.

(3) The affected area shall be limed with at least fifty pounds (50 lbs.) of agricultural grade lime per one hundred square feet (100 ft²)of affected area and tilled to a depth of at least four inches (4”).

(4)(A) Based on the quantity and areal extent of the produced water spill, the proximity of the spill area to surface water features, the nature of the soil, and land use of the area, and any impact to public safety, the director may require additional remediation action to be taken by the permit holder.

(B) These additional actions may include:

(i) Flushing of the area with freshwater (which shall be collected and disposed in a permitted Class II well);

(ii) The addition of organic material (e.g., peat moss, hay, straw);

(iii) Additional chemical treatment;

(iv) Additional disking of the soil; or

(v) Soil removal.

(C) The operator shall be required to continue these corrective actions until the spill remediation efforts are deemed complete by the director based on site-specific conditions.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book; amended September 17, 2007)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-223 Determining and naming common sources of supply {#sec-15-car-275-223 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-223}

15 CAR § 275-223. Determining and naming common sources of supply.

(a) Wells shall be classified as to the common sources of supply from which they produce, and common sources of supply shall be determined and named by the Oil and Gas Commission, provided that in the event any person is dissatisfied with any such classification or determination, an application may be made to the commission for such classification or determination deemed proper, and the commission will hear and determine the same.

(b)(1) In naming the common sources of supply, preference shall be given to common usage and geographical names.

(2) Separate common sources of supply within the same area shall preferably be named according to the producing formation.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-224 Takings to be ratable {#sec-15-car-275-224 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-224}

15 CAR § 275-224. Takings to be ratable.

(a) Every person, now or hereafter engaged in the business of purchasing and selling crude oil or natural gas in this state, shall purchase, without discrimination in favor of one (1) producer against another, or in favor of any one (1) source of supply as against another.

(b) For purposes hereof, a distinction shall exist between crude oil and natural gas purchased from oil wells and gas wells as those wells are respectively defined within 15 CAR § 275-103 and takings shall be deemed to be ratable when purchases are made without discrimination between wells within each such separate classification.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-225 Dual completion of wells {#sec-15-car-275-225 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-225}

15 CAR § 275-225. Dual completion of wells.

(a) A permit holder may elect to complete a well in such a manner as to permit the production of oil or gas from one (1) formation through the tubing and oil or gas from a separate formation through the annular space between the tubing and casing, subject to the following conditions, that:

(1) Each well dually completed shall be regarded as a separate and distinct well;

(2) The production shall be taken and measured separately; and

(3) All rules and orders governing individual oil or gas wells shall be strictly adhered to.

(b) A permit holder may file an application with the Director of Production and Conservation to complete a gas well for production of dry gas from a formation through the annular space between the production casing and the surface casing, provided the following conditions are met:

(1) Each application shall be made on a form prescribed by the director and shall include:

(A) Proof of written notice to all offset operators or owners, as defined in Arkansas Code § 15-72-109, in governmental sections that are contiguous to the lease upon which uncontrolled gas is to be produced; or

(B) If controlled, then proof to all offset operators or owners, as defined in Arkansas Code § 15-72-109, having the right to produce from the same shallow formation in the adjacent governmental sections;

(2) Surface casing in the subject well has been set and cemented to a depth as required by 15 CAR § 275-213; and

(3) The proposed zone to be produced would otherwise not be economic due to limited production potential.

(c) Any offset operator or owner noticed in accordance with subdivision (b)(1) of this section, above, shall have the right to object to the granting of such application within fifteen (15) days after receipt of the application by the Oil and Gas Commission.

(d)(1) If an objection is received within fifteen (15) days after receipt of the application by the commission, or if the permit holder does not satisfy all requirements of subsection (b) of this section, the application shall be denied.

(2) If an application is denied, the permit holder may request to have the matter placed, in accordance with established procedures, on the docket of a regularly scheduled commission hearing.

(e) If no objection is received by the commission within fifteen (15) days after receipt of the application by the commission, and the permit holder is in compliance with all requirements of subsection (b) of this section, the application shall be approved.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book; amended December 16, 2007)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-226 Establishment of field rules {#sec-15-car-275-226 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-226}

15 CAR § 275-226. Establishment of field rules.

(a)(1) An application for the purpose of establishing field rules, and well spacing and drilling units for a new reservoir or pool, except within the covered lands specified in 15 CAR § 275-230 or 15 CAR § 275-231, shall be submitted, in accordance with 15 CAR §§ 275-101 and 275-102, and applicable hearing procedures, to the Oil and Gas Commission within six (6) months after the initial completion of the discovery well in a pool or reservoir or after the drilling of three (3) wells, whichever occurs first.

(2) Prior to receipt of an application, no further permits to drill more than three (3) wells in the same source of supply in the exploratory area as defined by the Director of Production and Conservation shall be issued.

(b)(1) Upon receipt by the commission of an application for public hearing to establish field rules, well spacing, and drilling units for a reservoir, additional permits beyond the initial three (3) wells may be issued to that reservoir or pool, provided the well permit applications comply with the drilling unit size and well location provision as contained in the application.

(2) Permits may continue to be issued until a hearing is held and a decision rendered.

(c) The commission may, after notice and hearing in accordance with 15 CAR §§ 275-101 and 275-102 and other applicable hearing procedures, grant exceptions to this section, provided such exceptions will create neither waste nor hazards conducive to waste.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book; amended September 16, 2006; amended August 17, 2008)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-227 Authorization for Director of Production and Conservation to administratively approve applications for exceptional well locations {#sec-15-car-275-227 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-227}

15 CAR § 275-227. Authorization for Director of Production and Conservation to administratively approve applications for exceptional well locations.

(a)(1) The Director of Production and Conservation or his or her designee is authorized to issue a drilling permit for a well proposed to be drilled, is being drilled, or has been drilled, but prior to commencement of production, at a location within an established drilling unit, which fails to conform to the drilling unit setback distance requirements as measured from the approximate center of the wellbore to unit boundary lines under applicable field rules or Oil and Gas Commission general rules.

(2) This section is only applicable to:

(A) Dry gas wells drilled vertically or directionally and does not apply to any type of dry gas well drilled as a wildcat well, as defined in 15 CAR § 275-203, or for dry gas wells drilled in exploratory units established by commission order;

(B) Oil or gas condensate wells drilled in standard drilling units from which the well setbacks are defined by distance from a drilling unit boundary defined by a legal land description and does not apply to drilling units where well setbacks are established by other methods, or for wildcat wells, or for wells in exploratory units established by the commission; or

(C) Oil wells located in uncontrolled fields where the standard well setback as specified in 15 CAR § 275-203 apply to lease lines rather than drilling unit lines.

(b)(1) In each such instance in which a permit is issued, except in uncontrolled fields which are not subject to an allowable, a reduction (penalty) in the allowable to which such well would otherwise be entitled, under the provisions of the applicable field rules or other general well spacing rules, shall be assessed by multiplying a fraction, the:

(A) Numerator of which shall be the distance expressed in feet between the location of such proposed well and the boundary of the drilling unit in which the well is to be drilled; and

(B) Denominator of which shall be the distance expressed in feet at which wells within such field and/or drilling unit are otherwise required to be located.

(2) If the proposed location encroaches upon more than one (1) boundary of said unit, then the penalty to be imposed upon the production allowable shall be cumulative of the penalties from both boundaries as described in subdivision (b)(3) of this section, below.

(3) If the proposed location encroaches upon more than one (1) boundary as specified in subdivisions (b)(1) and (2) of this section, above, the reduction in the allowable shall be calculated as follows:

First boundary encroachment expressed as: setback footage specified by rule (minus)(–) actual footage of proposed well from unit boundary (divided by)() setback footage specified by rule, plus (+)

Second boundary encroachment expressed as: setback footage specified by rule (minus)(–) actual footage of proposed well from unit boundary (divided by)(÷) setback footage specified by rule = penalty factor

Then: penalty factor (x) full calculated allowable (Mcf or bbl) = amount allowable reduced (Mcf or bbl)

Then: full calculated allowable (Mcf or bbl) (minus)(–) amount allowable reduced (Mcf or bbl) = production allowable (Mcf or bbl)

(4) Each such application for an exceptional location shall be submitted on a form prescribed by the director, accompanied by an application fee of five hundred dollars ($500) and include the name and address of each owner, as defined in Arkansas Code § 15-72-102(9), within the drilling unit in which the proposed well is to be drilled and within the drilling units offsetting the boundary line or lines, or in the case of wells in uncontrolled fields, within the boundaries of mineral lease lines and the offsetting lease or leases, which shall be encroached upon by the proposed exceptional well location.

(5) Concurrently with the filing of an application in accordance with this section, the applicant shall send to each owner specified in subdivision (b)(4) of this section, above, a notice of the application filing and verify such mailing by affidavit, setting out the names and addresses of all owners and the date of mailing.

(6)(A) Any owner noticed in accordance with subdivision (b)(4) of this section, shall have the right to object to the granting of such application within fifteen (15) days after the receipt of the application by the commission.

(B) Each objection must be made in writing and filed with the director.

(C) If a timely written objection is filed as herein provided, then the applicant shall be promptly furnished a copy of such objection and the application shall be denied.

(D) If the application is denied under this subdivision (b)(6), the applicant may request to have the application placed, in accordance with 15 CAR §§ 275-101 and 275-102, and other applicable hearing procedures, on the docket of a regularly scheduled commission hearing for a commission determination, except that no additional application fee is required.

(7) An application may be referred to the commission for determination when the director deems:

(A) The penalty to be imposed upon the allowable for such well, calculated as herein provided, to be inadequate to offset any advantage which the applicant may have over any other producer, as defined in Arkansas Code § 15-72-102(8), by reason of the drilling of the well at such exceptional location; or

(B)(i) It necessary that the commission make such determination for the purpose of protecting correlative rights of all parties.

(ii) Promptly upon such determination, and not later than fifteen (15) days after receipt of the application, the director shall give the applicant written notice, citing the reason or reasons for denial of the application under this section and the referral to the full commission for determination.

(8)(A) Applications for exceptional locations resulting from directional drilling shall be considered for administrative approval in accordance with this section, provided that no allowable shall be authorized until the commission has been furnished a bottom hole directional survey for each common source of supply for which an allowable is requested.

(B) In all such cases where directional surveys are made available, the distance of the mid-point perforations for each common source of supply in a directional well from the drilling unit boundary shall be used in calculating the allowable.

(9) If the director has not notified the applicant of the determination to refer the application to the commission within the fifteen-day period in accordance with the foregoing provisions, and if no objection is received at the office of the commission within the fifteen (15) days as provided for in subdivision (b)(6) of this section, the application shall be approved and a drilling permit issued.

(c)(1) For dry gas wells, as specified in subdivision(a)(2)(A) of this section, above, an alternative to a reduction in the allowable (penalty) method, as outlined in subsection (b) of this section, above, may be requested if:

(A) Each affected drilling unit has been previously integrated by commission order or is one hundred percent (100%) leased, and is currently held by production; and

(B) All the working interest owners in each affected drilling unit agree, in writing, to share the proceeds from a well which encroaches upon the drilling unit boundary.

(2) The below methodology for determining percentages for the sharing of costs, production, and royalty among the affected drilling units, may be administratively authorized by the director or his or her designee.

(3) The method for determining the percentages for sharing the costs of and the proceeds of production from one (1) or more separately metered wells shall be as follows:

(A)(i) For vertical or directionally drilled wells, the acreage within an agreed upon area extending out from the perforated interval, as defined in 15 CAR § 275-203, shall be calculated for each such separately metered well (the calculated area).

(ii) The calculated area shall be based upon the estimated drainage area of the perforated interval;

(B) Each calculated area shall be allocated and assigned to each drilling unit according to that portion of the calculated area occurring within each drilling unit;

(i) Submitted on a form prescribed by the director accompanied by an application fee of five hundred dollars ($500); and

(ii) Include the name and address of each owner, as defined in Arkansas Code § 15-72-102(9), within each of the drilling units in which:

(a) The proposed well is to be drilled and/or completed; and

(b) Contains a portion of the calculated area as defined in subdivision (c)(3)(A) of this section, above;

(D) Concurrently with the filing of an application utilizing the above methodology, the applicant shall send in written authorization from each owner specified in subdivision (c)(3)(C) of this section, above;

(E)(i) An application may be referred to the commission for determination when the director deems it necessary that the commission make such determination for the purpose of protecting correlative rights of all parties.

(ii) Promptly upon such determination, and not later than fifteen (15) days after receipt of the application, the director shall give the applicant written notice citing the reason or reasons for denial of the application under this section and the referral to the full commission for determination;

(F) If the director has not notified the applicant of the determination to refer the application to the commission within the fifteen-day period in accordance with the foregoing provisions, and if no objection is received at the office of the commission within the fifteen (15) days as provided for in subdivision (c)(3)(E), the application shall be approved and a drilling permit issued;

(G)(i) Upon receipt of the drilling permit, the applicant shall give the other working interest parties written notice that the drilling permit has been issued.

(ii) The working interest parties, who have not previously made an election, shall have fifteen (15) days after receipt of said notice within which to make an election to participate in the well or be deemed as electing nonconsent and subject to the nonconsent penalty set out in the existing joint operating agreement covering their respective drilling unit; and

(H) Following completion of the well and prior to the issuance by the commission of the certificate of compliance to commence production, the final location of the perforated interval shall be submitted to the commission to verify the proposed portion of the calculated area occurring within each drilling unit as specified in subsection (c)(3)(A) of this section, above.

History

Codification Notes: “bbl” means barrel of crude oil."Mcf" means one thousand cubic feet (1,000 ft3).This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book; amended (Order 1-94(4)) January 25, 1994; amended July 17, 2006; amended December 16, 2007; amended August 17, 2008)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-228 Rule for operation in hydrogen sulfide (H2S) areas {#sec-15-car-275-228 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-228}

15 CAR § 275-228. Rule for operation in hydrogen sulfide (H₂S) areas.

(a)(1) Each operator who conducts operations in known areas of hydrogen sulfide (H₂S) with minimum concentrations of fifteen parts per million (15 ppm) under atmospheric conditions or one hundred parts per million (100 ppm) or more in the gas stream shall provide safeguards to protect the general public from the harmful effects of hydrogen sulfide (H₂S).

(2) The Director of Production and Conservation shall determine the areas covered by this section.

(b)(1) Operations shall include drilling, completion, workover, producing, gathering, and storage of:

(A) Hydrocarbon fluids;

(B) Natural gas; and

(2) These operations fall under these guidelines only if they contain gas in the system which has hydrogen sulfide (H₂S) as a constituent of the gas.

(1) “Area of exposure” means the area within a circle constructed with the point of escape as its center and the radius of exposure as its radius;

(2) “Contingency plan” means a written document that shall provide an organized plan of action for alerting and protecting the public within an area of exposure following the accidental release of a potentially hazardous volume of hydrogen sulfide;

(3) “Public area” means a dwelling, place of business, church, school, hospital, school bus stop, governmental building, a public road, all or any portion of a park, town, city, village, or other similar area that can be populated at any given time;

(4) “Public road” means any federal, state, county, or municipal street or road owned or maintained for public access or use; and

(5) “Radius of exposure” means that radius constructed with the point of escape as its starting point and its length calculated as provided for in subdivision (d)(4) of this section.

(d) General provisions.

(1)(A) Each operator shall determine the hydrogen sulfide (H₂S) concentration in the gaseous mixture in an operation or system.

(B) Test of vapor accumulation in storage tanks may be made with industry accepted colorimetric tubes.

(2)(A) Each operator shall immediately notify the Oil and Gas Commission of any accidental release of hydrogen sulfide (H₂S) gas which measures fifteen parts per million (15 ppm) or greater from any point on a radius which exceeds one hundred feet (100’) from the point of release, or includes any portion of a public area.

(B) Such notification shall be followed by a written report which shall be sent to the commission within ten (10) days of the incident.

(3) Each operator shall notify the commission before conducting any well servicing activity on any well operated under the provisions of this section.

(4)(A) For all operations subject to a radius of exposure (ROE), that radius shall be determined by the following Pasquill-Gifford Equations:

ROE = 100 ppm X = [(1.589)(mole fraction of H₂S)(Q)]^.6258 2. ROE = 500 ppm X = [(0.4546)(mole fraction of H₂S)(Q)]^.6258

Where X = radius of exposure in feet H₂S = mole fraction of hydrogen sulfide in the gaseous mixture established by an industry accepted method. Q =maximum volume of escapable gas in cubic feet per day.

(B) For drilling of a well where insufficient data exist to calculate an ROE, but where hydrogen sulfide may be expected, then a radius of exposure shall be three thousand feet (3,000’).

(5) Wind indicators shall be installed at strategic locations on or near the drilling, workover, or production facility to indicate the wind direction at all times and the safe upwind areas in the event hydrogen sulfide becomes present.

(e) Storage tank provisions. Storage tanks which are utilized as a part of a production operation, and which are operated at or near atmospheric pressure, and where the vapor accumulation has a hydrogen sulfide (H₂S) concentration in excess of one hundred parts per million (100 ppm), shall be subject to the following:

(1) No determination of a radius of exposure shall be made for storage tanks as herein described;

(2) A warning sign shall be posted on or within fifty feet (50’) of the facility to alert the general public of the potential danger;

(3)(A) All tank hatches shall be kept closed at all times except for when it is necessary to inspect or gauge such tanks.

(B) All storage tanks that are not fenced as required in subdivision (e)(4) of this section, below, are required to be kept secured by locks on the hatches on all such tanks when not being inspected or gauged;

(4)(A) Entry should be restricted to essential personnel only.

(B) As a security measure, fencing is required when storage tanks are inside the limits of a city, townsite, or are reasonably exposed to the public.

(5)(A) All hydrogen sulfide (H₂S) fumes and vapors shall be either recovered by a vapor recovery unit, flared through a flare stack with a permanent pilot attached thereon, or on a case-by-case basis vented by permit only.

(B) Permits to vent will be reviewed with respect to the:

(i) Distance to the nearest public receptor;

(ii) Concentration of hydrogen sulfide (H₂S) gas; and

(iii) Volume to be released.

(f) Warning and marker provision.

(1) A warning sign shall be maintained on all streets or roads which provide access to the facility.

(2) Marker signs shall be installed along the pipeline when it is located within a public area and at each public road crossing or along a public road, at intervals frequent enough in the judgment of the operator so as to provide warning to avoid the accidental rupturing of line by excavation.

(3) The marker sign shall contain sufficient information to establish the ownership and existence of the line and shall indicate by the use of the words, “Poison Gas”, that a potential danger exists.

(4) In satisfying the sign requirement, the following will be acceptable:

(A) A sign of sufficient size to be readable at a reasonable distance from the facility; and

(B) Existing signs installed prior to the effective date of this section will be acceptable if they indicate the existence of a potential hazard.

(g) Control and equipment safety provision.

(1) Operators subject to this provision shall:

(A) Install safety devices and maintain them in an operable condition; and

(B) Establish safety procedures designed to prevent the undetected continuing escape of hydrogen sulfide (H₂S).

(2) Safety devices should be tested annually and a record of each test maintained.

(h) Drilling and workover provisions.

(1) A certificate of compliance form (HS-1) must be filed with each intent to drill a well in an area and to a depth known to or that may contain hydrogen sulfide gas.

(2)(A) Drilling operations are required to be in compliance with the provisions of the section when the drilled depth is within one thousand feet (1,000’) of a zone known to or that may contain hydrogen sulfide.

(B) A variance from the compliance depth may be approved upon written request setting out justification, however, the compliance depth will not be less than five hundred feet (500’).

(3) Protective breathing equipment shall be maintained for all personnel at the site.

(4) As a minimum, hydrogen sulfide sensors for drilling or workover rigs shall be located at the rig floor, bell nipple, shale shaker, and mud pits unless otherwise approved by the director.

(5)(A) Blowout preventers and well control systems shall be pressure tested initially either to a minimum of three thousand pounds per square inch gauge (3,000 psig) or to seventy-five percent (75%) of the internal yield (burst) pressure taken from the API casing properties table for the size and grade of casing being used, whichever is less.

(B) Thereafter, all well control systems shall be tested prior to reaching compliance depth.

(C) The commission shall be notified at least four (4) hours prior to the initial Blowout Preventer and Well Control System Test.

(D) The commission shall have the authority to vary test procedures as is deemed necessary.

(6) Secondary remote control of blowout prevention and choke equipment shall be located away from the rig floor at a safe distance from the wellhead.

(7) The operator shall:

(A) Install a choke manifold, mud-gas separator, and flare line; and

(B) Provide a suitable method for lighting the flare.

(8) Drill stem testing.

(A) Drill stem testing of hydrogen sulfide (H₂S) zones is permitted only in daylight hours.

(B)(i) The commission shall be notified a minimum of twelve (12) hours in advance of the intention to conduct a drill stem test of a formation containing hydrogen sulfide (H₂S).

(ii) In the event that hydrogen sulfide (H₂S) is anticipated during the drill stem test, all testing and safety equipment shall be on location for use as deemed necessary by the commission.

(D)(i) Every precaution should be made not to affect the public during the well test.

(ii) In the event that residents are within the radius of exposure or may be affected by a drill stem test, the operator should contact those residents and inform them of the pending action.

(iii) Special consideration should be given to residents with children and/or medical ailments.

(9) A supervisory employee or safety company representative that is specifically trained in the operation, maintenance, and testing of all safety equipment and is knowledgeable of the contingency plan and safety procedures must be on site from the compliance depth through the cementing of the long string (production) casing and during the time in which the actual completion work is being performed on the well.

(10) API publication RP-49 and RP-68 is referenced as a suggested guideline for drilling and workover of wells subject to the provision.

(i) Contingency plan provision.

(1) All operators whose operations are subject to this provision shall develop a written contingency plan complete with all requirements before hydrogen sulfide (H₂S) operations are begun.

(2) The purpose of the contingency plan shall be to provide an organized plan of action for alerting and protecting the public following the accidental release of a potentially hazardous volume of hydrogen sulfide (H₂S).

(3) The contingency plan shall be activated immediately upon the detection of an accidental release of hydrogen sulfide (H₂S) which exceeds fifteen parts per million (15 ppm) or greater from any point on a radius which exceeds one hundred feet (100’) from the point of release, or includes any portion of a public area.

(4) Conditions that might exist in each area of exposure shall be considered when preparing a contingency plan.

(5) The plan shall include instructions and procedures for alerting the general public and public safety personnel of the existence of an emergency.

(6) The plan shall include a procedure for requesting assistance and for follow-up action to evacuate the public from an area of exposure.

(7) The plan shall include a call list which will include the following as they may be applicable:

(A) Local supervisory personnel;

(B) The commission;

(D) Division of Arkansas State Police;

(E) Ambulance service;

(F) Hospital;

(G) Fire department;

(H) Contractors for supplemental equipment;

(I) Division of Emergency Management of the Department of Public Safety; and

(J) Other public agencies as needed.

(8)(A) The plan shall include a plat detailing the area of exposure.

(B) The plat shall include the locations of private dwellings, residential areas, public facilities such as schools, business locations, public roads, or other similar areas where the public might reasonably be expected within the area of exposure.

(9) A schematic of the facility indicating all equipment on location should be included.

(10) The commission shall be notified immediately if the contingency plan is activated.

(11) The retention of the contingency plan shall be as follows:

(A) The plan shall be available for commission inspection at the well location; and

(B) The plan shall be retained at the location which lends itself best to activation of the plan.

(12)(A) The plan shall be kept updated to ensure its current applicability.

(B) Each plan must be reviewed and updated annually and a copy of the updated plan submitted to the commission in January of each calendar year.

(j) Training provision.

(1) Each operator and contractor shall provide appropriate hydrogen sulfide (H₂S) training for its employees who will be on site.

(2) All personnel must have in their possession current proof of annual training.

(3) This training should include the following:

(A) Hazards and characteristics of hydrogen sulfide (H₂S);

(B) Operations of safety equipment and life support systems;

(D) Use and operation of hydrogen sulfide (H₂S) monitoring equipment; and

(E) Emergency response procedures to include corrective actions, shutdown procedures, evacuation routes, and rescue methods.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-229 Seismic rules {#sec-15-car-275-229 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-229}

15 CAR § 275-229. Seismic rules.

(a) Definitions. As used in this section:

(1) “Field seismic operations” means any geophysical method performed on the surface of the land utilizing certain instruments operating under the laws of physics respecting vibration or sound to determine conditions below the surface of the earth which may contain oil or gas and is inclusive of, but not limited to, the:

(A) Preliminary line survey;

(B) Acquisition of necessary permits;

(D) Necessary clearing of vegetation;

(E) Shot hole drilling;

(F) Implantation of charge;

(G) Placement of geophones;

(H) Detonation; and

(I) Backfill of shot holes; and

(2) “Seismic shoot” means a specific project during which field seismic operations shall be conducted with due diligence, not to exceed or substantially vary from those seismic operations indicated in the original permit application.

(b)(1) Any person desiring to perform field seismic operations within the State of Arkansas shall obtain a permit for each seismic shoot from the Oil and Gas Commission prior to commencing field seismic operations.

(2) A copy of the approved permit shall be maintained in the central recording unit used for the seismic shoot.

(3) Such permit shall be valid for a period of one (1) year from the date of issuance.

(d) Each application as filed shall be accompanied by an application fee of five hundred dollars ($500).

(e)(1) Each application for a 2D seismic shoot shall include information and maps to:

(A) Identify the seismic shoot area;

(B) Indicate the proposed location of all 2D seismic lines; and

(C) Designate an area, each a 2D seismic line corridor within which a 2D seismic line may be located or relocated by permittee.

(2) No 2D seismic line corridor shall extend farther than one-half (1/2) mile in either direction from the proposed location of the relevant 2D seismic line.

(3) Applicants may omit areas within the outer boundaries of any 2D seismic line corridor from the 2D seismic line corridor.

(4) Each application for a 3D seismic shoot shall include information and maps to identify the seismic shoot area including the 3D project outline for such seismic shoot.

(5) Any relocations of a 2D seismic line or any portion thereof outside the 2D seismic line corridor designated therefore or any increase in a 3D survey outline shall be immediately reported to the director.

(6) The applicant shall also be required to file an amended application showing the revised location of such relocated 2D seismic lines, if applicable.

(7)(A) The applicant may also file a request, in writing, that the application with all information and maps be kept confidential for a period not to exceed twelve (12) months from the date of the filing of the original application.

(B) Subject to any applicable exceptions, including without limitation the trade secret exception to the general requirements of the Freedom of Information Act of 1967, Arkansas Code § 25-19-101 et seq., said application and any information and maps submitted may be released to the extent required by a court of law or by applicable state law, regardless of the request that such be kept confidential.

(8) Said application and any information and maps may also be introduced by the commission as evidence in any public hearing before the commission or in any judicial action, regardless of such request, provided, however, that permit holder shall retain the right to:

(A) Object to their admissibility; and

(B) Seek a closed hearing or a protective order with respect thereto.

(f)(1) The application shall be accompanied with evidence of the appropriate type of financial assurance, as described in 15 CAR § 275-202(d), and subject to those conditions listed therein.

(2) The financial assurance shall be at least fifty thousand dollars ($50,000), but not more than two hundred fifty thousand dollars ($250,000), provided that the aggregate amount of financial assurance required for any applicant for all permits and expired permits issued pursuant to this section shall not exceed two hundred fifty thousand dollars ($250,000).

(3) The amount of the financial assurance shall be determined by the director based on, but not limited to, the proximity of the seismic shoot to populated areas, cultural features, sensitive environmental areas, and past commission enforcement history against the applicant.

(4) The financial assurance required to be filed shall remain in effect for one (1) year following the conclusion of all field seismic operations by the permit holder in the State of Arkansas.

(g)(1) Upon review of a completed permit application, the director shall either issue the permit or deny the permit application.

(2) If the permit application is denied, the applicant may file an application for a hearing to appeal the director’s decision in accordance with 15 CAR §§ 275-101 and 275-102, and other applicable hearing procedures.

(h)(1) No entry shall be made by any person to conduct field seismic operations upon the lands where such field seismic operations are to be conducted without the permit holder having first given notice at least ten (10) calendar days prior to commencement of field seismic operations.

(2) The notice shall be in writing and given either personally or by certified United States Postal Service to the surface owners reflected in the tax records of the counties where the lands are located at the mailing addresses identified for such surface owners in such records.

(3)(A) In instances where it can be reasonably ascertained that there are occupants residing on the lands who are not the surface owners, such notice shall also be given such occupants, unless there is no known mailing address and personal notice cannot reasonably be given.

(B) Any such notice to an occupant shall be deemed delivered if delivered personally or deposited in the United States Postal Service postage prepaid to said occupants at the mailing address of the lands.

(4) Written notice shall also be given either personally or by certified United States Postal Service to operators, as reflected in the records of the commission, of producing wells within the seismic shoot area at the mailing addresses identified for such operators in said records.

(5) The notice shall contain the:

(A) Name of the person or entity that is conducting the field seismic operations;

(B) Proposed location of the field seismic operations; and

(i) The permit holder shall also notify the commission within five (5) business days of the commencement and completion of each seismic shoot.

(j) All vehicles utilized by the permit holder, or its agents or contractors, shall be clearly identified by signs or markings, utilizing letters and/or numbers a minimum of three inches (3”) in height and one-half inch (1/2”) wide, indicating the name of such agent.

(k)(1) No shot hole shall be drilled nor charge detonated within two hundred feet (200’) of any residence, water well, oil well, gas well, brine well, injection well, or other structure without having first secured the express written authority of the owner or owners thereof, and the permit holder shall be responsible for any resulting damages in accordance with this section.

(2) Written authority must also be obtained from the owner or owners if any charge exceeds the maximum allowable charge within the scaled distance below:

MAXIMUM ALLOWABLE DISTANCE TO CHARGE STRUCTURE (FT)* WEIGHTS (LBS)* 50 0.5 100 2.0 150 4.5 200 8.0 250 12.0 300 18.0 350 25.0

*Based upon a charge weight of seventy (70) FT/LB ½

(l) The maximum allowable charge weight is twenty-five pounds (25 lbs.), unless the permit holder requests and secures the prior written authorization from the director.

(m)(1) All holes drilled for field seismic activity shall be properly back filled with soils and/or other suitable material, and tamped.

(2) A mound may be left over the hole for settling allowance.

(n)(1) All seismic sources placed for detonation for use in field seismic operations shall contain additives to accelerate the biodegradation thereof and shall be handled with due care in accordance with industry standards.

(2) The cap leads for any seismic sources that fail to detonate shall be buried at least three feet (3’) deep.

(o) All vegetation cleared to the ground for the purposes of field seismic activity shall be cleared in a competent and workmanlike manner in the exercise of due care.

(p)(1) Unless otherwise consented to by the surface owner in writing, permit holder shall not cut down any tree measuring six inches (6”) or more in diameter, as measured at a height of three feet (3’) from the ground surface unless there are no reasonable alternatives to the removal of such tree or trees available to permit holder.

(2) Permit holder shall compensate surface owner the value of all such trees as determined by a forester licensed by the State of Arkansas.

(q) All excessive rutting or soil disturbances resulting from seismic activity shall be repaired or restored to the original condition and contour to the extent reasonable, unless otherwise agreed to by the permit holder and the surface owner in writing.

(r) All fences removed for the purposes of field seismic activity shall be replaced, unless otherwise agreed to by the permit holder and the surface owner in writing.

(s) All debris associated with the seismic activity shall be removed and properly disposed.

(t)(1) Any person who conducts any field seismic operations for a seismic shoot in the state without having obtained a permit therefore shall be subject to a civil penalty of one thousand dollars ($1,000) for each day such field seismic operations continue.

(2) Any person who does not fully comply with any other provision of this section shall be subject to a civil penalty of one thousand dollars ($1,000) for each violation.

(u) Failure to comply with the provisions of this section or Arkansas Code § 15-71-114, as amended, or any other applicable orders or rules of the commission may result in the forfeiture of the financial assurance to remediate damages or recover civil penalties assessed in accordance with subsection (t) of this section, above.

(v) In addition, any surface owner may seek to recover damages from the financial assurance as follows:

(1)(A) Any surface owner seeking to recover under such financial assurance for damages caused by the performance of such field seismic operations must file written notice of claim, on a form prescribed by the director, within one (1) year of the date of expiration of the permit.

(B) Provided, however, that such claim shall be subordinate to the rights of the commission;

(2)(A) Any claim received from a surface owner shall be investigated by the director and a decision shall be rendered by the director.

(B) If the director’s decision is not satisfactory to either the surface owner or the permit holder, either party may file an application for a hearing to appeal the director’s decision in accordance with 15 CAR §§ 275-101 and 275-102, and other applicable hearing procedures.

(i) Actual damages occurred;

(ii) Such damages were caused by:

(a) The negligence of the permit holder;

(b) A violation of this section by the permit holder; or

(c) An unreasonable or excessive use of the surface owner’s land by the permit holder under the applicable oil and gas lease or other agreement under which the surface owner and/or mineral owner consents to the use of the surface for seismic operations; and

(iii) The amount of such damages;

(3)(A) If the commission finds that the permit holder is liable to the surface owner for any such damages, the permit holder shall have thirty (30) days from the effective date of the order to pay the surface owner the amount specified by the commission.

(B) If the permit holder fails to pay the amount specified by the commission to the surface owner, the director may initiate bond forfeiture proceedings as described in 15 CAR § 275-202(k) to pay damages specified by the commission, provided, however, that such amount shall be subordinate to the rights of the commission; and

(4) If the permit holder’s financial assurance is forfeited, the permit holder shall cease all field seismic operations until another bond in the same amount of the original bond is filed with the commission for the same purposes as the original bond.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book; amended July 3, 2003; amended June 15, 2008)" Authorities: Arkansas Code § 15-71-110; Arkansas Code § 15-71-114

15 CAR § 275-230 Establishment of drilling units for gas production from conventional and unconventional sources of supply occurring in certain prospective areas not covered by field rules {#sec-15-car-275-230 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-230}

15 CAR § 275-230. Establishment of drilling units for gas production from conventional and unconventional sources of supply occurring in certain prospective areas not covered by field rules.

(a) For purposes of this section, “unconventional sources of supply” means those common sources of supply that are identified as the Fayetteville Shale, the Moorefield Shale, and the Chattanooga Shale Formations, or their stratigraphic shale equivalents, as described in published stratigraphic nomenclature recognized by the Arkansas Geological Survey or the United States Geological Survey.

(b) For purposes of this section, “conventional sources of supply” means all common sources of supply that are not defined as unconventional sources of supply in subsection (a) of this section, above.

(c)(1) This section is applicable to all occurrences of conventional and unconventional sources of supply in Arkansas, Cleburne, Conway, Cross, Faulkner, Independence, Jackson, Lee, Lonoke, Monroe, Phillips, Prairie, St. Francis, Stone, Van Buren, White, and Woodruff counties, Arkansas, and shall be called the “subsection (c) lands”.

(2) The development of the conventional and unconventional sources of supply within the subsection (c) lands shall be subject to the provisions of this section.

(d)(1) This section is further applicable to all occurrences of unconventional sources of supply in Crawford, Franklin, Johnson, and Pope counties, Arkansas, and shall be called the “subsection (d) lands”.

(2) The development of the unconventional sources of supply within the subsection (d) lands shall be subject to the provisions of this section.

(3) For purposes of this section, the subsection (d) lands and the subsection (c) lands may collectively be referred to as the “covered lands”.

(e)(1) All Oil and Gas Commission approved Fayetteville Shale and non-Fayetteville Shale fields that are situated within the subsection (c) lands and that are in existence on the date this section is adopted (collectively, the “existing fields”), are abolished and the lands heretofore included within the existing fields are included within the subsection (c) lands governed by this section.

(2) Further, all amendments that added the Fayetteville Shale Formation to previously established fields for conventional sources of supply occurring in the subsection (d) lands are abolished and continuing development of the Fayetteville Shale and other unconventional sources of supply in these lands shall be governed by the provisions of this section.

(3) All existing individual drilling units, however, contained within the abolished fields shall remain intact.

(f)(1) All drilling units established for conventional and unconventional sources of supply within the subsection (c) lands and all drilling units established for unconventional sources of supply within the subsection (d) lands shall be comprised of single governmental sections, typically containing an area of approximately six hundred forty (640) acres in size.

(2) Each drilling unit shall be characterized as either an “exploratory drilling unit” or an “established drilling unit”.

(3) An “exploratory drilling unit” means any drilling unit that is not an established drilling unit.

(4)(A) An “established drilling unit” means any drilling unit that contains a well that has been drilled and completed in a conventional or unconventional source of supply (a “subject well”), and for which the operator or other person responsible for the conduct of the drilling operation has:

(i) Filed with the commission all appropriate documents in accordance with 15 CAR § 275-205; and

(ii) Been issued a certificate of compliance.

(B) Upon the filing of the required well and completion reports for a subject well and the issuance of a certificate of compliance with respect thereto, the exploratory drilling unit upon which the subject well is located and all contiguous governmental sections shall be automatically reclassified as established drilling units.

(g)(1) The filing of an application to integrate separately owned tracts within an exploratory drilling unit, as defined in subsection (f) of this section, above, and as contemplated by Arkansas Code § 15-72-302(e), is permissible provided that one (1) or more persons who collectively own at least an undivided fifty percent (50%) interest in the right to drill and produce oil or gas, or both, from the total acreage assigned to such exploratory drilling unit support the filing of the application.

(2) In determining who shall be designated as the operator of the exploratory drilling unit that is being integrated, the commission shall apply the following criteria:

(A)(i) Each integration application shall contain a statement that the applicant has sent written notice of its application to integrate the drilling unit to all working interest owners of record within such drilling unit.

(ii) This notice shall contain a well proposal and AFE for the initial well and may be sent at the same time the integration application is filed;

(B)(i) If any nonapplicant working interest owner in the drilling unit owns, or has the written support of one (1) or more working interest owners that own, separately or together, at least a fifty percent (50%) working interest in the drilling unit, such nonapplicant working interest owner may:

(a) Object to the applicant being named operator (a “subsection (g) operator challenge”); or

(b) File a competing integration application (a “subsection (g) competing application”) that challenges any aspect of the original integration application for such drilling unit.

(ii) Any contested matter that is limited to a subsection (g) operator challenge shall be heard at the commission hearing that was originally scheduled for such integration application.

(iii) Any contested matter that involves the filing of a subsection (g) competing application shall be postponed until the next month’s regularly scheduled commission hearing if postponement is requested by either competing applicant;

(C) If a party desiring to be named operator of a drilling unit is supported by a majority-in-interest of the total working interest ownership in the drilling unit (the “majority owner”), the majority owner shall be designated unit operator;

(D) In the event two (2) parties desiring to be named operator own, or have the written support of one (1) or more working interest owners that own, exactly, an undivided fifty percent (50%) share of the drilling unit, and either a subsection (g) operator challenge is submitted or a subsection (g) competing application is filed, operatorship shall be determined by the commission based on the factors it deems relevant and the evidence submitted by the parties or as otherwise provided by subsequent rule; and

(E) If the person designated as operator by the commission in the adjudication of a subsection (g) operator challenge or a subsection (g) competing application does not commence actual drilling operations on the drilling unit within the twelve-month period set out in the integration order, such operator shall not be entitled to be designated as operator under the subsequent integration of such drilling unit unless:

(i) The operator’s failure to commence such drilling operations was due to force majeure; or

(ii) A majority-in-interest of the total working interest ownership in the drilling unit, excluding such designated operator, support such operator.

(h)(1) The filing of an application to integrate separately owned tracts within an established drilling unit, as defined in subsection (f) of this section, above, and as contemplated by Arkansas Code § 15-72-303, is permissible without a minimum acreage requirement, provided that one (1) or more persons owning an interest in the right to drill and produce oil or gas, or both, from the total acreage assigned to such established drilling unit requests such integration.

(2) In determining who shall be designated as the operator of the established drilling unit that is being integrated, the commission shall apply the following criteria:

(ii) This notice shall contain a well proposal and AFE for the initial well and may be sent at the same time the integration application is filed;

(B)(i) Any nonapplicant working interest owner in the drilling unit may object to the applicant being named operator (a “subsection (h) operator challenge”).

(ii) In addition, if an objecting party owns, or has the written support of one (1) or more working interest owners that own, separately or together, a larger percentage working interest in the drilling unit than the applicant, such objecting party may file a competing integration application (a “subsection (h) competing application”) that challenges any aspect of the original integration application for such drilling unit.

(iii) Any contested matter that is limited to a subsection (h) operator challenge shall be heard at the commission hearing that was originally scheduled for such integration application.

(iv) Any contested matter that involves the filing of a subsection (h) competing application shall be postponed until the next month’s regularly scheduled commission hearing if postponement is requested by either competing applicant;

(C) If a party desiring to be named operator of a drilling unit is a majority owner, as defined in subdivision (g)(2)(C) of this section, above, the majority owner shall be designated unit operator;

(D)(i) If a party desiring to be named operator of a drilling unit is not a majority owner, but is supported by the largest percentage interest of the total working interest ownership in the drilling unit (the “plurality owner”), there shall be a rebuttable presumption that the plurality owner shall be designated unit operator.

(ii) If a subsection (h) operator challenge to a plurality owner being designated unit operator is submitted by a party that owns, or has the written support of one (1) or more owners that own, separately or together, the next largest percentage share of the working interest ownership in the drilling unit (the “minority owner”), the commission may designate the minority owner operator if the minority owner is able to show that, based on the factors the commission deems relevant and the evidence submitted by the parties, the commission should designate the minority owner as unit operator;

(E) If two (2) or more parties that desire to be named operator own, or have the support of one (1) or more working interest owners that own, separately or together, the same working interest ownership in the drilling unit, operatorship shall be determined by the commission based on the factors it deems relevant and the evidence submitted by the parties, or as otherwise provided by subsequent rule; and

(F) If the person designated as operator by the commission in the adjudication of a subsection (h) operator challenge or a subsection (h) competing application does not commence actual drilling operations on the drilling unit within the twelve-month period set out in the integration order, such operator shall not be entitled to be designated operator under the subsequent integration of such drilling unit unless:

(i) The original operator’s failure to commence drilling operations on the initial well was due to force majeure; or

(ii) A majority-in-interest of the total working interest ownership in the drilling unit (excluding the original operator) support the original operator.

(i) The well setback from drilling unit boundary lines and spacing between wells, for wells drilled in drilling units for unconventional sources of supply within the covered lands are as follows:

(1) Each well location, as defined in 15 CAR § 275-203(a)(2), shall be at least five hundred sixty feet (560’) from any drilling unit boundary line, unless an exception is granted by the commission after notice and hearing in accordance with 15 CAR §§ 275-101 and 275-102, and other applicable hearing requirements, or in accordance with subsection (o) of this section, below;

(2) The perforated interval of the wellbore shall be at least five hundred sixty feet (560’) in any direction from any other wellbore perforated interval in the same common source of supply that extends across or encroaches upon drilling unit boundaries, unless an exception is granted in accordance with subdivision (i)(5) of this section, below;

(3) The perforated interval of the wellbore shall be at least four hundred forty-eight feet (448’) in any direction, an allowed twenty percent (20%) variance, from all other wellbore perforated intervals in the same common source of supply within an established drilling unit, unless an exception is granted in accordance with subdivision (i)(5) of this section, below;

(4)(A) No more than sixteen (16) wells may be drilled per unit for each separate unconventional source of supply within an established drilling unit unless an exception is granted by the commission after notice and hearing in accordance with 15 CAR §§ 275-101 and 275-102, and other applicable hearing requirements.

(B) For purposes of this subdivision (i)(4) only, a well is any vertical well, directional well, or horizontal well with, at a minimum, five hundred sixty feet (560’) of perforated interval in the drilling unit, or if a horizontal well does not contain a minimum of five hundred sixty feet (560’) of perforated lateral in any one (1) drilling unit, then the horizontal well shall be counted in the drilling unit in which the majority of the perforated lateral occurs; and

(5) The Director of Production and Conservation or his or her designee is authorized to approve an application requesting an exception to subdivision (i)(2) of this section and/or subdivision (i)(3) of this section administratively, if the following conditions are met:

(A) Each such application shall:

(i) Be submitted on a form prescribed by the director; and

(ii) Include the name and address of each owner, as defined in Arkansas Code § 15-72-102(9), within each of the drilling units in which the proposed well is to be drilled and/or completed;

(B)(i) Concurrently with the filing of the application for an exceptional location in accordance with subdivision (i)(2) of this section and/or subdivision (i)(3) of this section, above, the applicant shall:

(a) Send to all owners, as defined in Arkansas Code § 15-72-102(9), whose mailing addresses may reasonably be ascertained, in all affected units, a notice of the application’s filing; and

(b) Verify such mailing by affidavit, setting out the names and addresses of all owners and the date of mailing.

(ii) Additionally, if there are any owners, as defined in Arkansas Code § 15-72-102(9), whose addresses were not reasonably ascertained and notice was not mailed, then the applicant shall also submit proof of publication of such notice in a newspaper of general circulation within the county or counties within which all the units are located that appeared at least one (1) time no earlier than three (3) days prior to filing the application, and no later than five (5) days after filing the application, prior to the director approving the application administratively;

(C)(i) Any owner, as defined in Arkansas Code § 15-72-102(9), so noticed, shall have the right to object to the granting of such application within fifteen (15) days after the receipt of the application by the commission.

(ii) Each objection must be made in writing and filed with the director.

(iv) If the application is denied under this subdivision (i)(5), the applicant may request to have the application referred to the commission for determination in accordance with 15 CAR §§ 275-101 and 275-102, and other applicable hearing requirements;

(D) If no timely objection is received, or if one is received and withdrawn within the original fifteen-day time period after receipt of the application, the director is authorized to approve the application administratively;

(iii) If the application is referred under this subdivision (i)(5), the applicant shall file a request for a hearing, in accordance with 15 CAR §§ 275-101 and 275-102, and other applicable hearing requirements, except that no additional filing fee is required;

(F) If the applicant has satisfied all applicable provisions, and the director has not notified the applicant of the determination to refer the application to the commission within the fifteen-day period in accordance with the foregoing provisions, and if no objection is received at the office of the commission within the fifteen (15) days as provided for in subdivision (i)(5)(C) of this section, above, the application shall be approved and a permit issued; and

(G) Any such application requesting administrative approval may be granted, provided the above criteria is satisfied, prior to the drilling of a well, while a well is being drilled, or after a well has been drilled and completed, but prior to commencement of production.

(6) Applications for exceptions to these well location provisions, relative to a drilling unit boundary or other locations in a common source of supply, may be brought before the commission.

(j) The well spacing for wells drilled in drilling units for conventional sources of supply within the subsection (c) lands are as follows:

(1) Only a single well completion will be permitted to produce from each separate conventional source of supply within each established drilling unit, unless additional completions are approved in accordance with 15 CAR § 275-408;

(2) Each well location, as defined in 15 CAR § 275-203(a)(2), shall be at least one thousand one hundred twenty feet (1,120’) from any drilling unit boundary line;

(3) Well completions located closer than one thousand one hundred twenty feet (1,120’) from all established drilling unit boundaries shall be subject to approval in accordance with 15 CAR § 275-227; and

(4) Applications for exceptions to these well location provisions, relative to a drilling unit boundary or other location in a common source of supply, may be brought before the commission.

(k) The casing programs for all wells drilled in exploratory and established drilling units established by this section and occurring in the covered lands specified by this section shall be in accordance with 15 CAR § 275-213.

(l)(1) Wells completed in and producing from only conventional sources of supply, as defined in subsection (b) of this section, shall be subject to the testing provisions of 15 CAR § 275-405 and production allowable provisions of 15 CAR § 275-410.

(2) Wells completed in and producing from only unconventional sources of supply, as defined in subsection (a) of this section, shall not be subject to the testing provisions of 15 CAR § 275-405 and allowable provisions of 15 CAR § 275-410.

(3) There shall be no production allowable established for wells producing from unconventional sources of supply located within the covered lands.

(4) Wells completed in and producing from only unconventional sources of supply within the covered lands shall report on a form prescribed by the director the highest twenty-four-hour production rate during the first forty (40) days of production, which form shall be filed within sixty (60) days of the date of first production from the well.

(m)(1) The commingling of completions for unconventional and/or conventional sources of supply within each well situated on an established drilling unit shall be subject to the provisions and approval process outlined in 15 CAR § 275-407.

(2) If an unconventional source of supply is approved to be commingled with a conventional source of supply within a well situated on an established drilling unit, the well shall be subject to the production allowable provisions of 15 CAR § 275-410.

(n)(1) The reporting requirements of 15 CAR § 275-205 shall apply to all wells subject to the provisions of this section.

(2) In addition, the operator of each such well shall be required to file monthly gas production reports in accordance with 15 CAR § 275-402.

(o)(1)(A) The commission specifically retains jurisdiction to consider applications brought before the commission from a majority-in-interest of all owners, as defined by Arkansas Code § 15-72-102(9), in two (2) or more adjoining drilling units seeking the authority to drill, produce, and/or share the costs of and the proceeds of production from one (1) or more separately metered wells that extend across or encroach upon drilling unit boundaries, and that are drilled and completed in one (1) or more unconventional sources of supply within the covered lands.

(B) All such applications shall contain a proposed agreement on the formula for the sharing of costs, production, and royalty from the affected drilling units.

(2) Encroaching wells. If a well encroaches upon but does not cross the drilling unit boundary of an adjoining drilling unit (an “encroaching well”), the commission shall not consider the encroached upon drilling unit to be held by production from the encroaching well.

(3) Administrative approval of wells that extend across or encroach upon drilling unit boundaries.

(A) If the majority-in-interest of all owners, as defined by Arkansas Code § 15-72-102(9), within each drilling unit agree to share a proposed well, a well that is being drilled, or a well which has been drilled, but prior to commencement of production, between two (2) or more adjoining drilling units which are all integrated or are one hundred percent (100%) leased utilizing the below methodology for sharing of costs, production, and royalty among the affected drilling units, the director or his or her designee is authorized to approve the application administratively, if the following conditions are met:

(i) The application provides proof that:

(a) There is at least one (1) well located, as defined in 15 CAR § 275-203(a)(2), at a nonexceptional well location and located entirely within each included drilling unit that is producing or capable of producing gas;

(b) Within twelve (12) months following the date the well for which administrative approval is granted is spud, there will be at least one (1) well located, as defined in 15 CAR § 275-203(a)(2), at a nonexceptional well location, and located entirely within each included drilling unit that is either a well that is producing gas, or a well that is capable of producing gas and awaiting connection to a pipeline;

(c) There is at least one (1) well or a combination of multiple wells, including cross unit wells and/or encroaching wells located, as defined in 15 CAR § 275-203(a)(2), within each included drilling unit that have a total combined perforated lateral length within the drilling unit of not less than four thousand one hundred sixty feet (4,160’), and are producing or are capable of producing gas;

(d) Within twelve (12) months following the date the well for which administrative approval is granted is spud, there will be at least one (1) well or a combination of multiple wells, including cross unit wells and/or encroaching wells located, as defined in 15 CAR § 275-203(a)(2), within each included drilling unit that have a total combined perforated lateral length within the drilling unit of not less than four thousand one hundred sixty feet (4,160’), and are producing or are capable of producing gas and awaiting connection to a pipeline; or

(e) At least seventy-five percent (75%) of the fee mineral ownership within each included drilling unit that does not contain one (1) or more wells satisfying the requirements of subdivision (o)(3)(A)(i)(a) of this section or subdivision (o)(3)(A)(i)(c) of this section, above, agree in writing to the well;

(ii) Notice has been given to all owners, as defined by Arkansas Code § 15-72-102(9), and no objections were received by the director in accordance with subdivision (o)(3)(G) of this section, below; and

(iii) The application includes detailed plat maps indicating current well locations and potential future well development plans in all included drilling units.

(B) If administrative approval is granted, based upon either or both of subdivision (o)(3)(A)(i)(b) or subdivision (o)(3)(A)(i)(d) of this section, above, and the applicant fails to satisfy one (1) of the conditions specified in subdivision (o)(3)(A)(i)(b) or subdivision (o)(3)(A)(i)(d) of this section, above, the drilling permit and all other authorities for the well shall be automatically revoked, and the well shall be shut in, unless the applicant has filed a request in accordance with 15 CAR §§ 275-101 and 275-102, and other applicable hearing procedures prior to the expiration of the time period specified in such subdivisions, or the commission otherwise approves the application.

(C) The method for sharing the costs of and the proceeds of production from one (1) or more separately metered wells shall be based on acreage allocation as follows:

(i) An area measured five hundred sixty feet (560’) along and on both sides of the entire length of the horizontal perforated section of the well, and including an area formed by a five-hundred-sixty-foot radius from the beginning point of the perforated interval, and a five-hundred-sixty-foot radius from the ending point of the perforated interval shall be calculated for each such separately metered well (the “calculated area”); and

(ii) Each calculated area shall be allocated and assigned to each drilling unit according to that portion of the calculated area occurring within each drilling unit.

(D) Each such application for utilizing the above methodology shall:

(i) Be submitted on a form prescribed by the director, accompanied by an application fee of five hundred dollars ($500); and

(ii) Include the name and address of each owner, as defined in Arkansas Code § 15-72-102(9), within each of the drilling units in which the proposed well is to be drilled and/or completed.

(E) Concurrently with the filing of an application utilizing the above methodology, the applicant shall send to each owner specified in subdivision (o)(3)(D) of this section, above, a notice of the application filing and verify such mailing by affidavit, setting out the names and addresses of all owners, as defined by Arkansas Code § 15-72-102(9), and the date of mailing.

(F)(i) Any owner, as defined by Arkansas Code § 15-72-102(9), noticed in accordance with subdivision (o)(3)(E) of this section, above, shall have the right to object to the granting of such application within fifteen (15) days after the receipt of the application by the commission.

(ii) Each objection must be made in writing and filed with the director.

(iii) If a timely written objection is filed as herein provided, then the applicant shall be promptly furnished a copy and such application shall be denied.

(iv) If the application is denied under this subdivision (o)(3), the applicant may request to have the application referred to the commission for determination, in accordance with 15 CAR §§ 275-101 and 275-102, and other applicable hearing requirements, except that no additional filing fee is required.

(G)(i) An application may be referred to the commission for determination when the director deems it necessary that the commission make such determination for the purpose of protecting correlative rights of all parties, in order to prevent waste, or for any other reason.

(iii) If the application is referred under this subdivision (o)(3), the applicant shall file a request for a hearing, in accordance with 15 CAR §§ 275-101 and 275-102, and other applicable hearing requirements, except that no additional filing fee is required.

(H) If the director has not notified the applicant of the determination to refer the application to the commission within the fifteen-day period in accordance with the foregoing provisions, and if no objection is received at the office of the commission within the fifteen (15) days as provided for in subdivision (o)(3)(G) of this section, the application shall be approved and a drilling permit issued.

(I)(i) Upon receipt of the drilling permit, the applicant shall give the other owners, as defined by Arkansas Code § 15-72-102(9), written notice that the drilling permit has been issued.

(ii) The owners, as defined by Arkansas Code § 15-72-102(9), who have not previously made an election, shall have fifteen (15) days after receipt of said notice within which to make an election to participate in the well or be deemed as electing nonconsent and subject to the nonconsent penalty set out in the existing joint operating agreement covering their respective drilling unit or units.

(J) Following completion of the well and prior to the issuance of the certificate of compliance to commence production, the final location of the perforated interval shall be submitted to the director to verify the proposed portion of the calculated area occurring within each drilling unit as specified in subdivision (o)(3)(C) of this section, above.

(4) Filing of affidavit. The applicant shall also file an affidavit or other document showing the calculated area allocated and assigned to each drilling unit, according to the final calculation of the area, occurring within each drilling unit with the:

(A) Director; and

(B) Real estate property records in all counties where any portion of the drilling units are located.

(p)(1) The commission shall retain jurisdiction to consider applications brought before the commission from a majority-in-interest of working interest owners in two (2) or more adjoining governmental sections seeking the authority to combine such adjoining governmental sections into one (1) drilling unit for the purpose of developing one (1) or more unconventional sources of supply.

(2) In any such multisection drilling unit, production shall be allocated to each tract therein in the same proportion that each tract bears to the total acreage within such drilling unit.

(q) The commission shall retain jurisdiction to consider applications, brought before the commission, from a majority-in-interest of working interest owners in a drilling unit seeking the authority to omit any lands from such drilling unit that are owned by a governmental entity and for which it can be demonstrated that such governmental entity has failed or refused to make such lands available for leasing.

History

Codification Notes: “AFE” means authorization for expenditure.This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: new rule October 16, 2006; amended December 16, 2007, amended June 15, 2008, amended December 14, 2008; amended March 25, 2010; amended July 05, 2010; amended August 01, 2014; amended October 1, 2015)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-231 Establishment of drilling units for gas production from all sources of supply occurring in certain producing areas in Franklin, Logan, Scott, Sebastian, and Yell counties {#sec-15-car-275-231 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-231}

15 CAR § 275-231. Establishment of drilling units for gas production from all sources of supply occurring in certain producing areas in Franklin, Logan, Scott, Sebastian, and Yell counties.

(a) Definitions. As used in this section:

(1) “Conventional sources of supply” means all common sources of supply that are not defined as:

(A) Unconventional sources of supply in subdivision (a)(4) of this section;

(B) The Middle Atoka as defined in subdivision (a)(2) of this section, below; or

(2) “Middle Atoka” means the tight gas formation that is the stratigraphic equivalent, from the top of the Basham Formation to the base of Borum Formation, which includes the Hartford Series, within the covered lands specified in subsection (b) of this section, below;

(3) “Tight gas formation” means tight gas formation as defined in Arkansas Code § 26-58-101; and

(4) “Unconventional sources of supply” means those common sources of supply that are identified as the Fayetteville Shale, the Moorefield Shale, and the Chattanooga Shale Formations, or their stratigraphic shale equivalents, as described in published stratigraphic nomenclature recognized by the Office of the State Geologist or the United States Geological Survey.

(b)(1) This section is applicable to all sources of supply occurring in the “covered lands”, except the Hartshorne Coal Formation or any other coal formation.

(2) The development of these sources of supply within the covered lands shall be subject to the provisions of this section.

(3) The covered lands are specified as follows:

(A) Sections 19-36, T7N R28W; Sections 1-3 and 11, T6N, R29W all in Franklin County;

(B) Sections 19-36 T7N R27W; Sections 19-36 T7N R26W; Sections 13-36 T7N R25W; Sections 13-36 T7N R24W; Sections 13-36 T7N R23W; all of T6N R28W; all of T6N R27W; all of T6N R26W; all of T5N R29W; all of T5N R28W; all of T5N R27W; all of T5N R26W; Sections 1, 2, 3, 10, 11, 12 T4N R29W; Sections 1-12 T4N R28W; Sections 1-12 T4N R27W; Sections 1-12 T4N R26W all in Logan County and those portions of T6N R25W, T6N R24W, and T6N R23W located in Logan County;

(C) That portion of T5N R30W, T4N R29W, T4N R28W, T4N R27W, and T4N R26W located in Scott County; and all of T4N R30W in Scott County;

(D) Sections 31-36 T7N R31W; Sections 31 and 32 T7N R30W; all of T6N R32W; all of T6N R31W; all of T6N R30W; all of T5N R32W; all of T5N R31W; all of T4N R32W and all of T4N R31W in Sebastian County and that portion of T6N R29W and T5N R30W located in Sebastian County; and

(E) All of T5N R25W; all of T5N R24W; all of T5N R23W; all of T4N R25W; all of T4N 24W; all of T4N R23W; all of T6N R22W; all of T5N R22W; all of T4N R22W all in Yell County and those portions of T6N R25W, T6N R24W, T6N R23W located in Yell County.

(4) After notice and hearing, the Oil and Gas Commission shall retain jurisdiction to expand the covered lands above to include other lands proven to possess production characteristics similar to the lands initially contained within the covered lands.

(c) The commission shall retain jurisdiction after notice and hearing to determine which other formations, in addition to the Middle Atoka, qualify as tight gas formations within the covered lands.

(d)(1) All commission approved fields, except those applicable to the Hartshorne Coal Formation or any other coal formation, that are situated within the covered lands and that are in existence on the date this section is adopted (collectively, the “existing fields”), are abolished, and the lands heretofore included within the existing fields are included within the covered lands governed by this section.

(2) However, all existing portions of the abolished fields which are not included in the covered lands, those portions of the fields shall remain intact and operate under the existing field rules for that field or, upon order of the commission, may be joined to other existing adjacent fields.

(3) All existing individual drilling units contained within the abolished fields shall remain intact.

(e)(1) All drilling units established for sources of supply within the covered lands shall be comprised of single governmental sections, typically containing an area of approximately six hundred forty (640) acres in size, unless a different size and/or configuration is approved for any unit or units by order of the commission.

(2) Each drilling unit shall be characterized as either an “exploratory drilling unit” or an “established drilling unit”.

(3) An “exploratory drilling unit” means any drilling unit that is not an established drilling unit.

(4) An “established drilling unit” means any drilling unit that contains a well:

(A) That has been drilled and completed in any source of supply (a “subject well”); and

(B) For which the operator or other person responsible for the conduct of the drilling operation has:

(i) Filed with the commission all appropriate documents in accordance with 15 CAR § 275-205; and

(ii) Been issued a certificate of compliance.

(5) Upon the filing of the required well and completion reports for a subject well and the issuance of a certificate of compliance with respect there, the exploratory drilling unit upon which the subject well is located and all contiguous governmental sections shall be automatically reclassified as established drilling units.

(6) All existing exploratory drilling units contiguously located to drilling units with established production at the time this section is adopted shall be automatically reclassified as established drilling units.

(f)(1) The filing of an application to integrate separately owned tracts within an exploratory drilling unit, as defined in subsection (e) of this section, above, and as contemplated by Arkansas Code § 15-72-302(e), is permissible, provided that one (1) or more persons who own at least an undivided fifty percent (50%) interest in the right to drill and produce oil or gas, or both, from the total acreage assigned to such exploratory drilling unit agree.

(2) In determining who shall be designated as the operator of the exploratory drilling unit that is being integrated, the commission shall apply the following criteria:

(ii) This notice shall contain a well proposal and AFE for the initial well and may be sent at the same time the integration application is filed;

(a) Object to the applicant being named operator, a “subsection (f) operator challenge”; or

(b) File a competing integration application, a “subsection (f) competing application”, that challenges any aspect of the original integration application for such drilling unit.

(ii) Any contested matter that is limited to a subsection (f) operator challenge shall be heard at the commission hearing that was originally scheduled for such integration application.

(iii) Any contested matter that involves the filing of a subsection (f) competing application shall be postponed until the next month’s regularly scheduled commission hearing if postponement is requested by either competing applicant;

(D) In the event two (2) parties desiring to be named operator own, or have the written support of one (1) or more working interest owners that own, exactly, an undivided fifty percent (50%) share of the drilling unit and either a subsection (f) operator challenge is submitted or a subsection (f) competing application is filed, operatorship shall be determined by the commission, based on the factors it deems relevant and the evidence submitted by the parties or as otherwise provided by subsequent rule; and

(E) If the person designated as operator by the commission in the adjudication of a subsection (f) operator challenge or a subsection (f) competing application does not commence actual drilling operations on the drilling unit within the twelve-month period set out in the integration order, such operator shall not be entitled to be designated as operator under the subsequent integration of such drilling unit unless:

(i) The operator’s failure to commence such drilling operations was due to force majeure; or

(ii) A majority-in-interest of the total working interest ownership in the drilling unit (excluding such designated operator) support such operator.

(g)(1) The filing of an application to integrate separately owned tracts within an established drilling unit, as defined in subsection (e) of this section, above, and as contemplated by Arkansas Code § 15-72-303 is permissible, without a minimum acreage requirement, provided that one (1) or more persons owning an interest in the right to drill and produce oil or gas, or both, from the total acreage assigned to such established drilling unit requests such integration.

(2) In determining who shall be designated as the operator of the established drilling unit that is being integrated, the commission shall apply the following criteria:

(ii) This notice shall contain a well proposal and AFE for the initial well and may be sent at the same time the integration application is filed;

(B)(i) Any nonapplicant working interest owner in the drilling unit may object to the applicant being named operator (a “subsection (g) operator challenge”).

(ii) In addition, if an objecting party owns, or has the written support of one (1) or more working interest owners that own, separately or together, a larger percentage working interest in the drilling unit than the applicant, such objecting party may file a competing integration application (a “subsection (g) competing application”) that challenges any aspect of the original integration application for such drilling unit.

(iii) Any contested matter that is limited to a subsection (g) operator challenge shall be heard at the commission hearing that was originally scheduled for such integration application.

(iv) Any contested matter that involves the filing of a subsection (g) competing application shall be postponed until the next month’s regularly scheduled commission hearing if postponement is requested by either competing applicant;

(C) If a party desiring to be named operator of a drilling unit is a majority owner, as defined in subdivision (f)(2)(C) of this section, above, the majority owner shall be designated unit operator;

(ii) If a subsection (g) operator challenge to a plurality owner being designated unit operator is submitted by a party that owns, or has the written support of one (1) or more owners that own, separately or together, the next largest percentage share of the working interest ownership in the drilling unit (the “minority owner”), the commission may designate the minority owner operator if the minority owner is able to show that, based on the factors the commission deems relevant and the evidence submitted by the parties, the commission should designate the minority owner as unit operator;

(F) If the person designated as operator by the commission in the adjudication of a subsection (g) operator challenge or a subsection (g) competing application does not commence actual drilling operations on the drilling unit within the twelve-month period set out in the integration order, such operator shall not be entitled to be designated operator under the subsequent integration of such drilling unit unless:

(i) The original operator’s failure to commence drilling operations on the initial well was due to force majeure; or

(ii) A majority-in-interest of the total working interest ownership in the drilling unit, excluding the original operator, support the original operator.

(h) The well spacing for wells drilled in exploratory and established drilling units for all unconventional sources of supply within the covered lands are as follows:

(1) Each well location, as defined in 15 CAR § 275-203(a)(2), shall be at least five hundred sixty feet (560’) from any drilling unit boundary line, unless an exception is approved in accordance with subsection (p) of this section, below, or in accordance with 15 CAR § 275-227; and

(2) Each well location, as defined in 15 CAR § 275-203(a)(2), shall be at least five hundred sixty feet (560’) from other well locations within an established drilling unit, within common sources of supply, unless an exception to this section is approved by the commission following notice and hearing.

(i) The well spacing for wells drilled in exploratory and established drilling units for the Middle Atoka, and any other tight gas formation source of supply within the covered lands are as follows:

(2) Each well location, as defined in 15 CAR § 275-203(a)(2), shall be at least five hundred sixty feet (560’) from other well locations within an established drilling unit, unless the common sources of supply are stratigraphically different named intervals, approved in accordance with subdivision (i)(3) of this section, below, or an exception to this section is approved by the commission following notice and hearing; and

(3)(A) Application for approval of well locations less than five hundred sixty feet (560’) from other well locations within an established unit, for common sources of supply from stratigraphically different named intervals, shall be submitted on a form prescribed by the Director of Production and Conservation, and contain, at a minimum, the following information:

(i) The location of the unit;

(ii) The location or proposed location of all wells being encroached upon, showing the productive zones in each well;

(iii) A cross-section, containing the location or proposed location of all wells being encroached upon, demonstrating what the productive zone will be from stratigraphically different named intervals; and

(iv)(a) In addition, each application shall provide proof of written notice to all owners, as defined in Arkansas Code § 15-72-102(9), in the subject unit.

(b) The notice shall contain, at a minimum, the name of the applicant, the name and location of the encroaching wells, and instructions as to the filing with the director written objections within fifteen (15) days after receipt of the application by the director.

(B) Any owner noticed in accordance with subdivision (i)(3)(A)(iv)(b) of this section, above, shall have the right to object to the granting of such application within fifteen (15) days after receipt of the application by the director.

(C) If an objection is not received within fifteen (15) days after the receipt of the application, and the productive zone will be from stratigraphically different named intervals, the director shall approve the application.

(D) If an objection is received, or if the application does not satisfy the requirements of this section and is denied by the director, the applicant may request to have the matter placed, in accordance with 15 CAR §§ 275-101 and 275-102 and other established procedures, on the docket of a regularly scheduled commission hearing.

(j) The well spacing for wells drilled in exploratory and established drilling units for the Upper Atoka and the Freiburg conventional sources of supply within the covered lands are as follows:

(k) The well spacing for wells drilled in exploratory and established drilling units for all other conventional sources of supply within the covered lands are as follows:

(1) Only a single well completion will be permitted to produce from each separate conventional source of supply within each exploratory or established drilling unit, unless additional completions are approved in accordance with 15 CAR § 275-408; and

(2) Each well location, as defined in 15 CAR § 203(a)(2), shall be at least one thousand one hundred twenty feet (1,120’) from any drilling unit boundary line, unless an exception is approved in accordance with subsection (p) of this section, below, or 15 CAR § 275-227.

(l) The casing programs for all wells drilled in exploratory and established drilling units established by this section, and occurring in the covered lands specified by this section, shall be in accordance with 15 CAR § 275-213 or other applicable general rules.

(m) Wells completed in and producing from all sources of supply within the covered lands shall be subject to the testing provisions of 15 CAR § 275-405 and allowable provisions of 15 CAR § 275-410, except that unconventional sources of supply shall not be subject to an allowable.

(n) The commingling of completions in all sources of supply within each well shall be subject to the provisions in 15 CAR § 275-407.

(o)(1) The reporting requirements of 15 CAR § 275-205 shall apply to all wells subject to the provisions of this section.

(2) In addition, the operator of each such well shall be required to file monthly gas production reports, on a form approved by the director, no later than forty-five (45) days after the last day of each month.

(p)(1) The commission specifically retains jurisdiction to consider applications brought before the commission from a majority-in-interest of working interest owners in two (2) or more adjoining exploratory or established drilling units seeking the authority to drill, produce, and share the costs of, and the proceeds of production from, a separately metered well that extends across or encroaches upon drilling unit boundaries and that are drilled and completed in one (1) or more sources of supply within the covered lands.

(2) All such applications shall contain a proposed agreement on the formula for the sharing of costs, production, and royalty from the affected drilling units.

(3) However, if the majority-in-interest of working interest owners agree to share a proposed well between two (2) or more adjoining drilling units, which have been previously integrated, utilizing the below methodology for sharing of costs, production, and royalty among the affected drilling units, or if the well encroaches upon the drilling unit boundaries specified by this section, the director or his or her designee is authorized to approve the application administratively utilizing the following methodology:

(A) The sharing of well costs and the proceeds of production from one (1) or more separately metered wells between the affected drilling units shall be based on an allocation based on an area (acreage) calculation as specified below;

(B)(i) For horizontal wells, an area, equal to the setback footage for that source of supply as specified in subsections (h), (i), (j), or (k) of this section, above, along and on both sides of the entire length of the horizontal perforated section of the well, and including an area formed by a radius, equal to the setback footage for that source of supply as specified in subsections (h), (i), (j), or (k) of this section, above, from the beginning point of the perforated interval and from the ending point of the perforated interval.

(ii) The area formed shall be calculated for each such separately metered well and referred to as the “calculated area”;

(C) For vertical wells, an area, equal to the setback footage for that source of supply as specified in subsections (h), (i), (j), or (k) of this section, above, extending around the perforated interval as defined in 15 CAR § 275-203, shall be calculated for each such separately metered well and referred to as the “calculated area”; and

(D) Each calculated area shall be allocated and assigned to each drilling unit according to that portion of the calculated area occurring within each drilling unit.

(4) Each such application for utilizing the above methodology shall be submitted on a form prescribed by the director, accompanied by an application fee of five hundred dollars ($500) and include the name and address of each owner, as defined in Arkansas Code § 15-72-102(9), within each of the drilling units in which the proposed well is to be drilled and/or completed.

(5) Concurrently with the filing of an application utilizing the above methodology, the applicant shall send to each owner specified in subdivision (p)(4) of this section, above, a notice of the application filing and verify such mailing by affidavit, setting out the names and addresses of all owners and the date of mailing.

(6)(A) Any owner noticed in accordance with subdivision (p)(5) of this section, above, shall have the right to object to the granting of such application within fifteen (15) days after the receipt of the application by the commission.

(B) Each objection must be made in writing and filed with the director.

(C) If a timely written objection is filed as herein provided, then the applicant shall be promptly furnished a copy and the application shall be denied.

(D) If the application is denied under subdivision (p)(1) of this section, the applicant may request to have the application referred to the commission for determination, in accordance with applicable state laws and 15 CAR §§ 275-101 and 275-102, except that no additional filing fee is required.

(7)(A) An application may be referred to the commission for determination when the director deems it necessary that the commission make such determination for the purpose of protecting correlative rights of all parties.

(B) Promptly upon such determination, and not later than fifteen (15) days after receipt of the application, the director shall give the applicant written notice citing the reason or reasons for denial of the application under this section and the referral to the full commission for determination, in accordance with applicable state laws and 15 CAR §§ 275-101 and 275-102.

(8) If the director has not notified the applicant of the determination to refer the application to the commission within the fifteen-day period in accordance with the foregoing provisions, and if no objection is received at the office of the commission within the fifteen (15) days as provided for in subdivision (p)(6) of this section, the application shall be approved and a drilling permit issued.

(9)(A) Upon receipt of the drilling permit, the applicant shall give the other working interest parties written notice that the drilling permit has been issued.

(B) The working interest parties, who have not previously made an election, shall have fifteen (15) days after receipt of said notice within which to make an election to participate in the well or be deemed as electing nonconsent and subject to the nonconsent penalty set out in the existing joint operating agreement covering their respective drilling unit or units.

(10) Following completion of the well and prior to the issuance by the commission of the certificate of compliance to commence production, the final location of the perforated interval shall be submitted to the commission to verify the proposed portion of the calculated area occurring within each drilling unit as specified in subdivision (p)(3) of this section, above.

(q)(1) The commission shall retain jurisdiction to consider applications brought before the commission from a majority-in-interest of working interest owners in two (2) or more adjoining governmental sections seeking the authority to combine such adjoining governmental sections into one (1) drilling unit for the purpose of developing one (1) or more unconventional sources of supply.

(2) In any such multisection drilling unit, production shall be allocated to each tract therein in the same proportion that each tract bears to the total acreage within such drilling unit.

(r) The commission shall retain jurisdiction to consider applications brought before the commission from a majority-in-interest of working interest owners in a drilling unit seeking the authority to omit any lands from such drilling unit that are owned by a governmental entity and for which it can be demonstrated that such governmental entity has failed or refused to make such lands available for leasing.

History

Codification Notes: “AFE” means authorization for expenditure.This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: new rule June 15, 2008; amended January 22, 2009; amended August 01, 2014)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-232 Establishment of well setback requirements for dry gas production wells occurring in established fields in Crawford, Franklin, Johnson, Logan, Madison, Pope, Scott, Yell, Sebastian, and Washington counties {#sec-15-car-275-232 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-232}

15 CAR § 275-232. Establishment of well setback requirements for dry gas production wells occurring in established fields in Crawford, Franklin, Johnson, Logan, Madison, Pope, Scott, Yell, Sebastian, and Washington counties.

(a) Applicability.

(1) Except as provided in subdivision (a)(2) of this section, below, this section applies to all controlled sources of supply as defined in Arkansas Code § 15-71-107, occurring within any existing field created by an order of the Oil and Gas Commission within Crawford, Franklin, Johnson, Logan, Madison, Pope, Scott, Yell, Sebastian, and Washington counties.

(2) This section does not apply to:

(A) The Hartshorne Coal Formation or any other coal formation;

(B) Any uncontrolled conventional source of supply occurring within the commission established fields covered by this section;

(D) Any source of supply governed by 15 CAR § 275-231.

(3) After notice and hearing, the commission shall retain jurisdiction to extend the provisions of this section to any new fields established by the commission.

(4) This section applies to wells in which controlled and uncontrolled sources of supply are commingled.

(b) Definitions. As used in this section:

(1) “Encroachment footage” means the actual footage of the new or existing PRU from the drilling unit boundary, when that footage is less than the setback footage specified by this section;

(2) “Existing PRU” means a production reporting unit, which is either an individual producing zone or approved commingled producing zones within a dry natural gas well which was previously productive prior to the effective date of this section;

(3) “FUB” means distance from a drilling unit boundary line;

(4) “New PRU” means a production reporting unit, which is either an individual producing zone (in a newly drilled dry natural gas well or a new zone in an existing dry natural gas well), or approved commingled producing zones within a dry natural gas well which becomes productive after the effective date of this section;

(5) “Penalty allowable” means the PRU deliverability of the new or existing PRU, subject to a penalty factor, a new or existing PRU is allowed to produce and sell on a per day basis;

(6) “Penalty factor” means the factor which is multiplied by the new or existing PRU to impose a penalty (or reduction) upon the PRU deliverability;

(7) "PRU deliverability" means the measured volume of dry natural gas from an existing or new PRU under normal operating conditions for that existing or new PRU as determined by the IOPT or production test; and

(8) “Setback footage” means the required minimum distance a new or existing PRU must be from the drilling unit boundary.

(c) After the effective date of this section, the setback footage for all drilling units subject to this section shall be as follows:

(1) For all existing drilling units with a setback footage that is less than six hundred sixty feet (660’), the setback footage shall remain unchanged; and

(2) For all existing drilling units with a setback footage that is six hundred sixty feet (660’) or greater, the revised setback footage shall be reestablished to six hundred sixty feet (660’).

(d) After the effective date of this section, any existing PRU not subject to a penalty allowable may produce at the PRU deliverability.

(e) After the effective date of this section, any new PRU not subject to a penalty allowable may produce at the PRU deliverability.

(f) The penalty allowable, for any existing or new PRU, after the effective date of this section, shall be determined as follows:

(1) For any existing PRU where the setback footage is equal to or greater than six hundred sixty feet (660’), and where the setback footage has been reestablished to six hundred sixty feet (660’) in accordance with subdivision (c)(2) of this section, above, the previously imposed penalty on the allowable established prior to the adoption of this section shall be removed and the existing PRU allowed to produce at the PRU deliverability;

(2) For any existing PRU where there is encroachment footage, and where the setback footage has been reestablished to six hundred sixty feet (660’) in accordance with subdivision (c)(2) of this section, above, the previously imposed penalty on the allowable established prior to the adoption of this section shall be recalculated based on the revised setback footage of six hundred sixty feet (660’) in order to calculate the penalty allowable, except that any existing PRU that has a recalculated penalty allowable of less than seventy-five (75) MCFD shall be assigned a penalty allowable of seventy-five (75) MCFD;

(3) For any existing PRU, where the setback footage remains unchanged in accordance with subdivision (c)(1) of this section, above, the penalty allowable established prior to the adoption of this section shall remain in effect, except that any existing PRU that has a recalculated penalty allowable of less than seventy-five (75) MCFD shall be assigned a penalty allowable of seventy-five (75) MCFD; and

(4) No new PRU may be located less than six hundred sixty feet (660’) FUB where the setback footage has been reestablished to six hundred sixty feet (660’) in accordance with subdivision (c)(2) of this section, above, or closer than the applicable setback footage that remained unchanged in accordance with subdivision (c)(1) of this section, above, unless approved in accordance with 15 CAR § 275-227, or an alternative is approved by the commission after notice and hearing.

(g) In accordance with subdivision (f)(2) of this section, above, the penalty allowable shall be calculated as follows:

(1) If the encroachment footage encroaches upon only one (1) boundary of said drilling unit, the penalty allowable shall be the greater of seventy-five (75) MCFD or calculated as follows:

Penalty Allowable = PRU Deliverability x Penalty Factor (Encroachment Footage ÷ Setback Footage) x proposed drilling unit acreage ÷ 640 acres or applicable established drilling unit acreage

(2) If the encroachment footage encroaches upon two (2) boundaries of said drilling unit, then the penalty allowable shall be the greater of seventy-five (75) MCFD or the cumulative of the penalties calculated as follows:

Penalty Allowable = PRU Deliverability x Penalty Factor [(1^st Encroachment Footage + 2nd Encroachment Footage) ÷ Setback Footage – 1] x proposed drilling unit acreage ÷ 640 acres or applicable established drilling unit acreage

(h) Sales in excess of the penalty allowable.

(1) An existing or new PRU subject to a penalty allowable in accordance with this section shall have an annual balancing date of July 1, where the preceding twelve-month (July 1 – June 30) sales must be reconciled with the preceding twelve-month penalty allowable to determine if the PRU had excess sales.

(2)(A) An existing or new PRU subject to a penalty allowable which has sales in excess of the assigned penalty allowable must be shut in on the annual balancing date of July 1 and remain shut in until all excess sales are eliminated.

(B) The shut-in period shall be determined by dividing the excess sales by the penalty allowable.

(3) Any existing or new PRU subject to a penalty allowable which has excess sales on the annual balancing date of July 1 and which fails to shut in within thirty (30) days after July 1, may be subject to a civil penalty not to exceed two thousand five hundred dollars ($2,500) per day for every day the PRU produced beyond the thirty-day period, and may be subject to further enforcement actions in accordance with 15 CAR § 275-104 and Arkansas Code §§ 15-72-401 — 15-72-406.

History

Codification Notes: “FUB” means from unit boundary."IOPT" means initial one-point test."MCFD" means a thousand cubic feet per day.This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: new rule August 01, 2014)" Authorities: Arkansas Code § 15-71-110; Arkansas Code § 15-71-114

Subpart 3

15 CAR § 275-301 Fields or pools in which production will be controlled {#sec-15-car-275-301 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-301}

15 CAR § 275-301. Fields or pools in which production will be controlled.

All common sources of supply of crude oil discovered after January 1, 1937, if so found necessary by the Oil and Gas Commission, will have the production of oil controlled or regulated as provided in Acts 1939, No. 105.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-302 Reports by producers {#sec-15-car-275-302 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-302}

15 CAR § 275-302. Reports by producers.

(a)(1) Each producer of oil in any field, and each producer of hydrocarbons in liquid form at the wellhead by ordinary production methods from a gas well in any field, shall execute in triplicate and file with the Oil and Gas Commission, El Dorado, Arkansas, a “Producer’s Certificate of Compliance and Authorization to Transport Oil or Gas from Lease”, for each lease that is capable of producing on or after July 15, 1955.

(2)(A) After the above date, whenever there shall occur a change in operating ownership of any lease in a field within the State of Arkansas, or whenever there shall occur a change of transporter from any lease in a field within the State of Arkansas, a new “Producer’s Certificate of Compliance and Authorization to Transport Oil or Gas from Lease”, shall be executed and filed in accordance with instructions appearing on such form, except that in the case of temporary change in transporter involving less than the allowable for one (1) month, the producer may, in lieu of filing a new certificate, notify the commission at El Dorado, Arkansas, and the transporter then authorized by certificate on file with the commission, by letter, of the estimated amount of oil to be moved by the temporary transporter and the name of such temporary transporter and a copy of such notice shall also be furnished such temporary transporter.

(B) In no instance shall the temporary transporter move any greater quantity of oil than the estimated amount shown in said notice.

(3) The “Producer’s Certificate of Compliance and Authorization to Transport Oil or Gas from Lease”, when properly executed and approved by the commission, shall constitute authorization to the pipeline or other carrier to transport oil from the lease named therein, and shall remain in force and effect until:

(A) The operating ownership of the lease changes;

(B) The transporter is changed; or

(4)(A) Where a transporter disconnects from a particular lease or ceases to remove oil therefrom and another transporter connects to such lease or begins to take oil therefrom, during a month, the transporter who ceases to take oil shall furnish to the connecting transporter a certified statement under oath, showing the:

(i) Legal quantity of oil on hand 7:00 a.m., the first day of such month;

(ii) Scheduled allowable to the date disconnected; and

(iii) Quantity of oil moved from the particular lease during the current month.

(B) In such case, the producer shall furnish to the connecting transporter a certified statement under oath showing the lease stock on hand 7:00 a.m., the date of new connection.

(C) No connecting transporter shall move oil from any such lease until after it shall have received such statements, except with the written permission of the commission or their authorized agent.

(5) Each producer is prohibited from delivering illegal oil to any transporter, and each transporter is prohibited from removing any illegal oil from producer’s lease tanks.

(6)(A) Each transporter shall maintain necessary records of lease allowables and quantities of oil removed from the leases to which he or she is connected, whereby he or she can determine the calculated quantity of legal oil on hand at the close of each calendar month with respect to such leases.

(B) The calculated quantity of legal oil on hand with respect to any lease shall be determined for each succeeding month by adding to the quantity of legally produced oil on hand at the first of the month, the scheduled allowable quantity of oil for the respective lease for the current month, as established by the commission, less the quantity of oil removed from the respective lease tanks during the current month.

(C) If the calculated balance so determined is less than the actual gauged quantity on hand as reported by the producer on the Producer’s Monthly Report, the transporter shall not remove during the following month any part of the oil on hand on the first day of the month in excess of the calculated legal balance so established.

(7)(A) If the actual quantity of oil on hand with respect to a particular lease equals or is less than the quantity of legal oil established by the above method, the transporter may remove any part or all of such quantity of oil during the current month.

(B) Where actual quantity of oil on hand with respect to a particular lease is less than the calculated quantity of legal oil established by the above method, the transporter, in determining the quantity of legal oil for the next succeeding month, shall substitute the actual quantity on hand for the calculated quantity on hand.

(C) Where there is more than one (1) transporter moving oil from the same lease, the producer and transporters are required to furnish to each other information as:

(i) The quantity of oil on hand;

(ii) The quantity transported from lease tanks; and

(iii) Any additional information necessary to establish to the satisfaction of each person involved the legal status of the oil produced.

(b)(1) Each producer of oil in any controlled oil field, and each producer of hydrocarbons in liquid form at the wellhead by ordinary production methods from a gas well in any controlled gas field, shall furnish for each calendar month a Producer’s Monthly Report, setting forth complete information and data indicated by such forms representing oil and/or liquid hydrocarbons produced from each lease operated by said producer in controlled fields in the State of Arkansas.

(2) Such report for each month shall be prepared and filed according to the instructions on the form, on or before the fifteenth of the next succeeding month.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-303 Oil assessment {#sec-15-car-275-303 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-303}

15 CAR § 275-303. Oil assessment.

Oil conservation assessment, in order to pay the costs in connection with oil and gas conservation administration not otherwise provided for, shall be made as follows:

(1)(A) There shall be assessed a charge not to exceed fifty (50) mills (Acts 2001, No. 1188) on each barrel of crude oil or petroleum marketed or used from a field or pool each month.

(B) Said charge and assessment shall only apply to the first purchase or use of oil from the producer and not to subsequent transfers commonly referred to as “tenderships”.

(2) The first purchaser, user, or holder for a period of thirty (30) days of the production, who is hereby defined to be the person holding the division order and issuing checks to pay for any working interest or royalty interest, shall before issuing checks or otherwise paying for the production, deduct the amount assessed per barrel of oil marketed, used or held for a period of thirty (30) days from the lease each month, and remit the amounts;

(3) Said remittance shall be made by the fifteenth of the month following the month in which the oil was purchased in a single check if the purchaser so desires, and the only accounting necessary by the purchaser shall be to show the deductions under this order on the regular payment statements to producers and royalty owners or parties in interest; and

(4)(A) Any person purchasing oil in this state at the well, under any contract or agreement requiring payment for such production to the respective owners thereof, in respect of which production any sums assessed under this section as payable to the Oil and Gas Commission, is hereby authorized, empowered, and required to deduct from any sum so payable to any such person the amount due the commission by virtue of any such assessment and remit that sum to the commission in the manner stated.

(B) Further, any person taking oil from any well in this state for use or resale, in respect of which production any sums assessed under the provisions of this section are payable to the commission, shall remit any sum so due to the commission in accordance with this part.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book; amended November 27, 2001)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-304 Establishment of well setback requirements for oil production wells {#sec-15-car-275-304 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-304}

15 CAR § 275-304. Establishment of well setback requirements for oil production wells.

(a) This rule pertains to oil well setback provisions specified in certain established field rules in Ashley, Bradley, Calhoun, Columbia, Hempstead, Lafayette, Miller, Nevada, Ouachita, and Union counties.

(b) In all established field rules covered by this section, all oil well setback provisions which are measured from a boundary other than the drilling unit boundary, and which are commonly referred to as “bull’s-eye” or “race-track” locations for ten-acre drilling units, described as a quarter (1/4) quarter (1/4) quarter (1/4) of a governmental section; twenty-acre drilling units, described as the east one-half (E/2), west one-half (W/2), north one-half (N/2), or south one-half (S/2) of a quarter (1/4) quarter (1/4) of a governmental section; forty-acre drilling units, described as a quarter (1/4) quarter (1/4) of a governmental section; and eighty-acre drilling units described as the east one-half (E/2), west one-half (W/2), north one-half (N/2), or south one-half (S/2) of a quarter (1/4) of a governmental section, are set at two hundred eighty feet (280’) from the drilling unit boundary and all existing bull’s-eye or race-track field rule setback requirements for the above drilling units are abolished.

(c) Established field rules with well setback requirements less than two hundred eighty feet (280’) from the above drilling unit boundaries, shall remain unchanged.

(d) Applications for exceptions to these well location provisions, relative to a drilling unit boundary or other location in a common source of supply, may be approved by the Oil and Gas Commission after notice and a hearing in accordance with 15 CAR §§ 275-101 and 275-102 and other applicable hearing procedures.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: new rule February 19, 2009)" Authority: Arkansas Code § 15-71-110

Subpart 4

15 CAR § 275-401 Natural gas to be metered {#sec-15-car-275-401 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-401}

15 CAR § 275-401. Natural gas to be metered.

(a) Wellhead production meters.

(1) For protection of correlative rights of all parties, the operator of a natural gas well shall meter or cause to be metered all natural gas produced from a well, utilizing a standard industry meter approved by the American Gas Association and capable of recording accurately the volume of natural gas produced at each well, unless another methodology, approved by the Director of Production and Conservation, is utilized to provide for proper production allocation back to the individual well from a central point production meter or central point sales meter, whichever meter occurs first.

(2)(A) All required meters shall be calibrated at least once per calendar year.

(B) The records of such calibration shall be maintained or made available by the operator of the well and shall be available for inspection by the Oil and Gas Commission.

(3) All required meters shall be accessible and viewable by the commission for the purpose of monitoring daily, monthly, and/or cumulative production volumes from individual wells.

(b) Sales meters.

(1) All meters measuring the volume of gas sold shall be calibrated at least once per year.

(2) The director or his or her designee shall be notified not less than seventy-two (72) hours prior to conducting the meter calibration, so as to allow the commission to witness such calibration.

(3) The records of such calibration shall be maintained by the person responsible for the meter and shall be available for inspection by the commission.

(4) Such records shall be maintained by the person responsible for the meter for a period of five (5) years.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book; amended January 22, 2009)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-402 Monthly natural gas production reports {#sec-15-car-275-402 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-402}

15 CAR § 275-402. Monthly natural gas production reports.

(a)(1) All natural gas produced and sold from oil wells and from gas wells within the State of Arkansas, except natural gas taken into a gasoline, cycling, or other extraction plant gathering system, which is required to be reported in accordance with the provisions of 15 CAR § 275-602, shall be reported by the operator monthly in a form prescribed by the Director of Production and Conservation.

(2) In cases where gas is sold by any person other than the operator, the operator shall remain responsible for reporting all production sold, unless the operator notifies the director in writing of the:

(A) Name and address of the person other than the operator who has sold gas;

(B) Specific month or months for which the person other than the operator who sold gas has failed to report the necessary information to the operator; and

(3) Any person other than the operator who sold gas and failed to report the necessary information to the operator shall then be responsible for reporting the monthly production sold not otherwise reported by the operator to the Oil and Gas Commission.

(b)(1) Monthly reports specifying the amount of natural gas produced and sold are required to be filed for each individual producing zone or approved commingled producing zones within a well, regardless of whether or not there was natural gas produced and sold during the month.

(2) The reports shall be filed on a form prescribed by the director and shall be filed with the commission sixty (60) days after the end of each month.

(3) Reports for inactive wells shall continue to be submitted until such time as the commission determines monthly reports are no longer required in accordance with applicable commission rules.

(c) Where natural gas is delivered to a gasoline extraction plant, cycling plant, or any other plant at which butane, propane condensate, kerosene, oil, or other liquid products are extracted from natural gas, such gas shall be reported in accordance with 15 CAR § 275-602.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book; amended November 16, 2008; amended August 21, 2009)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-403 Gas assessment {#sec-15-car-275-403 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-403}

15 CAR § 275-403. Gas assessment.

(a) An assessment to pay the conservation expenses and other costs in connection with administration of gas conservation not otherwise provided for may be made as follows:

(1)(A) There shall be assessed against the persons involved a charge not to exceed ten (10) mills on each one thousand cubic feet (1,000 ft³) of gas produced and saved each month from a well.

(B) Said assessments shall apply only to the first purchase of gas, or the original taking from the well, and not the subsequent transfers, commonly referred to as “tenderships”.

(2) The person selling gas at the first point of sale, who is hereby defined to be the party initially responsible for distributing the one-eighth (1/8) royalty interest shall, before paying for the production, deduct nine (9) mills for every thousand cubic feet of gas produced and removed from the lease each month, and remit the amounts so deducted to the Oil and Gas Commission at the same time and periods as said purchasers make their regular gas payments;

(3) Said remittances may be made each month in a single check if the person selling gas at the first point of sale so desires, and no accounting by the person selling gas at the first point of sale shall be required except to show all deductions on the regular payment statements to producers and royalty owners or the parties in interest;

(4) The assessment herein provided for shall not apply to gas which is being returned to the ground for repressuring or pressure maintenance purposes within the field, but shall apply only to such gas as is produced and removed from the lease and returned to the ground for storage purposes; and

(5) Any person selling gas at the first point of sale in this state at the well, under any contract or agreement requiring payment for such production to the respective owners thereof, in respect of which production any sums assessed under this part are payable to the commission, is hereby authorized, empowered, and required to deduct from any sum so payable to any such person the amount due the commission by virtue of any such assessment and remit that sum to the commission.

(b) Further, any person taking gas from any well in this state for use or resale, in respect of which production any sums assessed under the provisions of this section are payable to the commission, shall remit any sum so due to the commission in accordance with this part.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book; amended November 27, 2001; amended October 24, 2009)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-404 Measuring gas at custody transfer points {#sec-15-car-275-404 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-404}

15 CAR § 275-404. Measuring gas at custody transfer points.

(a) No meter or meter run used for measuring gas at custody transfer points will be equipped with a manifold which will allow gas flow to be diverted or bypassed around the metering element with the following exceptions:

(1) Equipment which permits the changing of the orifice plate without bleeding the pressure off the gas meter run shall not be considered a bypass if flow is bypassed only during normal maintenance or verification operations; or

(2)(A) A manifold having block valves on each end of the meter run, and two (2) bypass valves with a bleeder between the bypass valves.

(B) During normal operations, the two (2) bypass valves will be closed, with at least one (1) bypass valve sealed, and the bleeder valve will be open and unplugged.

(b)(1) Whenever the manifold described in subdivision (a)(2) of this section is employed, a notation will be made on the orifice meter chart any time a seal is broken or replaced.

(2) This notation will include:

(A) The seal number broken;

(B) The seal number replaced;

(D) Graphic representation of the estimated gas flow during the time the meter is out of service.

(c) The party choosing to utilize, construct, or operate a bypass of the type described in subdivision (a)(2) of this section will assume all risks, responsibilities, and liabilities associated with said bypass.

(d) Existing meters used for measuring gas at custody transfer points shall be retrofitted in conformity herewith within twenty-four (24) months from the effective date hereof, provided, however, that meters to be installed at additional transfer points from and after the effective date hereof shall be in conformity herewith.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-405 Back pressure tests for natural gas production allowable determination {#sec-15-car-275-405 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-405}

15 CAR § 275-405. Back pressure tests for natural gas production allowable determination.

(a) Applicability. This section shall only apply to dry natural gas wells for which it is necessary to determine the PRU deliverability in accordance with 15 CAR §§ 275-105, 275-230, 275-231, 275-408, and 275-410, or the request of the Director of Production and Conservation or his or her designee to conduct a back pressure test on a dry natural gas well.

(b) Definitions. As used in this section:

(1) “Existing PRU” means a production reporting unit, which is either an individual source of supply or approved commingled producing zones within a dry natural gas well which was previously productive prior to the effective date of this section;

(2) “IOPT” means an initial one-point test performed to determine PRU deliverability;

(3) “New PRU” means a production reporting unit, which is either an individual producing zone (in a newly drilled dry natural gas well or a new zone in an existing dry natural gas well) or approved commingled producing zones within a dry natural gas well which becomes productive after the effective date of this section;

(4) “Permit holder” means the person to whom the permit is issued and who is responsible for all regulatory requirements relative to the production well;

(5) “Production test” means any one-point test that is performed to determine PRU deliverability which occurs after a successful one-point test has been performed; and

(6) "PRU deliverability" means the measured volume of dry natural gas from an existing or new PRU under normal operating conditions for that existing or new PRU as determined by the IOPT or production test.

(c)(1) An IOPT shall be conducted for any new PRU for the purpose of determining the PRU deliverability.

(2) If a new PRU cannot be tested to determine the PRU deliverability, a written explanation setting forth in detail the reasons why such IOPT cannot be obtained shall be submitted, along with a request for an alternative methodology to determine the PRU deliverability.

(d) Further production testing of an existing or new PRU following an IOPT is not required except for purposes of retesting at the request of the permit holder to establish a penalty allowable in accordance with 15 CAR § 275-410, determining marginal well status for severance tax purposes in accordance with 15 CAR § 275-105, an additional completion request in accordance with 15 CAR § 275-408, or if requested by the director or his or her designee.

(e) IOPT or production testing requirements.

(1) Notice. The permit holder of the PRU shall provide notice in the manner prescribed by the director or his or her designee at least seventy-two (72) hours in advance of an IOPT or a production test.

(2) When to conduct test.

(A) The permit holder shall conduct the IOPT within ten (10) calendar days of commencement of production of a new PRU.

(B) The director or his or her designee shall retain the right to require a retest of an existing or new PRU at any time.

(3) Filing of documents. The permit holder shall submit the results of the IOPT or production test within ten (10) business days of the test date.

(4) Commission staff witness.

(A) The IOPT is required to be witnessed by a representative of the Oil and Gas Commission unless the permit holder is notified by the commission that the test shall not be witnessed.

(B) Production tests for purposes of establishing marginal well determination, in accordance with 15 CAR § 275-105, are required to be witnessed by a representative of the commission.

(C) The commission staff witness will be subject to notice by the permit holder in accordance with subdivision (e)(1) of this section, above, and subject to availability of a committee staff witness.

(D) All tests shall be conducted during normal working hours of the commission unless otherwise approved by the director or his or her designee.

(f) Testing methodology.

(1) An IOPT or production test shall be conducted to determine the PRU deliverability.

(2) All tests shall be reported on a form prescribed by the director or his or her designee and conducted as follows:

(A) Before a test is started, the wellbore should be cleared of any accumulated fluids;

(B)(i) The dry natural gas from the existing or new PRU shall be flowed through the production facilities into the pipeline for a minimum of twenty-four (24) hours.

(ii) All flow rate measurements shall be obtained by the use of an orifice meter or other authorized metering device in good operating condition previously approved by the director or his or her designee; and

(C)(i) Should the flow rate not be obtained to determine PRU deliverability, the permit holder shall provide a written explanation setting forth in detail the reasons why such flow rate could not be obtained in accordance with this procedure.

(ii) The director or his or her designee may authorize an alternative method to determine PRU deliverability.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book; amended (Order No. 74-94) October 25, 1994; amended October 1, 2000; amended January 14, 2008; amended February 19, 2009; amended August 21, 2009; amended August 01, 2014)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-406 General rule for the regulation of natural gas pipelines {#sec-15-car-275-406 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-406}

15 CAR § 275-406. General rule for the regulation of natural gas pipelines.

(a) Definitions. As used in this section:

(1) “Jurisdictional pipeline” means any onshore natural gas pipeline regulated under Federal Regulation 49 C.F.R. pt. 192, as amended, which is within the jurisdiction of the Oil and Gas Commission in accordance with Arkansas Code § 15-71-110, as amended;

(2) “Nonjurisdictional pipeline” means any onshore natural gas pipeline, including but not limited to flowlines, production lines, or gathering lines, not under jurisdiction of Federal Regulation 49 C.F.R. pt. 192, as amended, which is within the jurisdiction of the Oil and Gas Commission in accordance with Arkansas Code § 15-71-110, as amended;

(3) “Perennial stream” means:

(A) A stream that has flowing water year-round during a typical year;

(B) The water table is located above the streambed for most of the year;

(D) Runoff from rainfall is a supplemental source of water for stream flow; and

(4) “Pipeline operator” means any person who owns or operates and is responsible for the construction, operation, and maintenance of a natural gas pipeline which transports natural gas from the well within the jurisdiction of the Oil and Gas Commission in accordance with Arkansas Code § 15-71-110, as amended.

(b) Applicability.

(1) For purposes of this section, the jurisdiction of the Oil and Gas Commission, as specified in Arkansas Code § 15-71-110, as amended, extends and includes:

(A) The production process or production facility as defined in Arkansas Code § 15-71-110, as amended; or

(B) A natural gas pipeline or associated facility whose owner is not affiliated with an Arkansas natural gas public utility and the majority owner is either a production company or an affiliate of a production company.

(2)(A) Every pipeline operator transporting natural gas by pipeline from the well is subject to the applicable provisions of this section.

(B) Natural gas pipelines from the well to a custodial transfer meter located on the well pad are exempt from the provisions of this section.

(1)(A) Each pipeline operator shall apply, on a form prescribed by the Director of Production and Conservation, for an initial statewide permit to construct and operate a natural gas pipeline system.

(B) The initial permit application shall contain at a minimum the following:

(i) Name, address, and contact information for the pipeline operator;

(ii) Map, or other media acceptable to the director, showing the location of all natural gas pipelines from the producing wells through any production or processing equipment or treating facility, and to the termination point of the jurisdiction of the commission, including all public road, railroad, and perennial stream crossings;

(iii) A determination as to what pipelines are jurisdictional; and

(iv) Submission of the applicable permit fee as follows:

(a) No permit fee is required for one (1) mile or less, provided the pipeline does not cross a public road, railroad, or perennial stream;

(b) Less than fifty (50) miles of pipeline, including pipelines in subdivision (c)(1)(B)(iv)(a) of this section, above, which cross a public road, railroad, or perennial stream – five hundred dollars ($500);

(d) One hundred (100) miles to less than two hundred fifty (250) miles of pipeline – two thousand five hundred dollars ($2,500); or

(e) Two hundred fifty (250) miles or more of pipelines – five thousand dollars ($5,000).

(2) Each pipeline operator shall be required to submit an annual permit renewal by January 31 of each year.

(3)(A) The renewal permit shall include a revised pipeline map showing any new pipeline additions constructed during the previous year, an annual report on a form prescribed by the director, along with a permit renewal fee in accordance with subdivision (c)(1)(B)(iv) of this section, above.

(B) The renewal permit shall also contain the pipeline operator’s determination as to which pipelines are jurisdictional.

(4)(A) Each pipeline operator shall submit a notice of construction or repair, on a form prescribed by the director, prior to commencing construction or within forty-eight (48) hours after completing repair, for each segment or project length of pipeline constructed during the year.

(B) The notice shall indicate the location and extent of the natural gas pipelines to be constructed or repaired.

(5)(A) Each pipeline operator shall notify the director or his or her designee within five (5) calendar days of exceeding any natural gas pipeline’s established maximum allowable operating pressure.

(B) This shall be submitted on a form prescribed by the director.

(6) Each pipeline operator shall submit a notice of incident, on a form prescribed by the director, for each incident of release due to natural gas pipeline failure which results in:

(A) A death or personal injury requiring inpatient hospitalization;

(B) A total cost of repair, including the value of natural gas lost, of ten thousand dollars ($10,000) or more; or

(C) An event that is significant, in the judgment of the operator, even though it did not meet the criteria of subdivisions (c)(6)(A) and (B) of this section, above.

(d) Requirements for all nonjurisdictional pipelines.

(1)(A) All pipelines crossing any stream or streambed shall comply with applicable state rules and federal regulations.

(B) Additionally, any stream crossing of perennial streams, constructed on or after December 16, 2007, shall maintain a minimum of fifty feet (50’) of undisturbed stream bank for the protection of the stream.

(C) However, the fifty feet (50’) of undisturbed stream bank requirement may be modified by the director provided that the pipeline operator provides proof that the pipeline operator has received approval for the crossing from a state or federal agency.

(2)(A) Each pipeline operator shall place and maintain appropriate signage at all natural gas pipeline crossings of public roads and railroads.

(B) The marker should include the words “Warning”, “Caution”, or “Danger” followed by the words “Gas Pipeline”, along with the pipeline operator’s name and telephone number where the pipeline operator can be reached at all times.

(3) Each pipeline operator which operates natural gas pipelines within the limits of any incorporated or unincorporated city, town, or village, shall be a member of a qualified one-call program.

(4) All natural gas pipelines, constructed after the effective date of this section, shall be buried at least twenty-four inches (24”) below ground surface, or in accordance with other applicable state or federal laws.

(e) Requirements for jurisdictional pipelines.

(1) All jurisdictional pipelines shall be in compliance with construction, operation, and maintenance requirements contained in federal regulations 49 C.F.R. pt. 192, Subparts A – P, as amended, which are herein incorporated by reference.

(2) All jurisdictional pipelines shall be subject to the applicable enforcement provisions of federal regulation 49 C.F.R. pt. 190, as amended, which are herein incorporated by reference.

(3) All jurisdictional pipelines shall be subject to the applicable incident and other reporting requirements contained in federal regulation 49 C.F.R. pt. 191, as amended, which are herein incorporated by reference, and all such reports shall be submitted to the commission.

(4) All pipeline operators of jurisdictional pipelines shall be subject to the applicable drug and alcohol testing requirements contained in federal regulation 49 C.F.R. pt. 199, as amended, which are herein incorporated by reference.

(5) All jurisdictional pipelines which contain over one hundred parts per million (100 ppm) hydrogen sulfide shall also be subject to the provisions of subsection (f) of this section, below, unless the provisions of subsection (f) of this section are less stringent than any applicable requirement of this subsection.

(f) Additional requirements for all pipelines containing one hundred parts per million (100 ppm) or greater hydrogen sulfide.

(1) Construction, operating, and maintenance requirements.

(A) All pipeline materials must be chemically compatible with any natural gas transported by the natural gas pipeline and such pipeline shall maintain structural integrity under the anticipated temperatures and environmental conditions for which the natural gas pipeline may be exposed.

(B) All piping must be of sufficient thickness or must be installed with adequate protection to withstand anticipated external pressures and loads that will be imposed on the pipe after installation.

(C) No natural gas pipeline may be operated after new construction, repair, or relocation until it has been successfully tested for at least one (1) hour with a minimum pressure of one and twenty-five hundredths (1.25) times the maximum operating pressure to substantiate the maximum operating pressure with all leaks located and eliminated.

(D) All metallic natural gas pipelines must be adequately protected from both external and internal corrosion and the pipeline operator is required to submit an annual report by March 31 of every year for the preceding calendar year of the effectiveness of the company’s corrosion program, with such protection efforts performed by an independent contractor specializing in the control of corrosion.

(2)(A) Each pipeline operator shall prepare, maintain, and follow for each natural gas pipeline, a manual of written procedures for conducting operations, maintenance activities, and emergency response.

(B) This plan must be reviewed and updated as often as necessary.

(3) Each pipeline operator shall:

(A) Have a procedure for continuing surveillance of its facilities; and

(B) Take appropriate action regarding failures, corrosion, and operating conditions.

(4)(A) Each pipeline operator must develop and carry out a damage prevention program to prevent damage to its natural gas pipelines from excavation activities.

(B) Each pipeline operator shall be a member of the statewide One Call Center system.

(C) The plan must have a method of communicating to excavators in the area where the natural gas pipeline is located of the existence of the natural gas pipeline, provide a means of receiving and recording notification of planned excavation activities, provide for temporary marking of the natural gas pipeline and inspection of the natural gas pipeline when the pipeline operator has reason to believe it could be damaged by excavation activities.

(5)(A) Each pipeline operator shall establish written procedures to minimize the hazards resulting from a natural gas pipeline emergency event.

(B) Each plan must include at a minimum:

(i) Methods of receiving and identifying an event which requires immediate response;

(ii) Methods for establishing and maintaining adequate communication with appropriate emergency response and public officials;

(iii) Methods for determining safe areas related to evacuation and security during an event; and

(iv) Methods for training employees of their duties and responsibilities during an event.

(6)(A) Each pipeline operator shall develop and implement a written continuing public awareness plan which includes provisions for educating the:

(i) Public;

(ii) Appropriate governmental organizations; and

(iii) Persons engaged in excavation activities.

(B) Use of a one-call notification prior to conducting excavation, possible hazards associated with unintended releases from the natural gas pipeline, physical indications that such a release may have occurred, steps that should be taken for the safety of the public, procedures for reporting such an event.

(C) The program must include activities to advise affected municipalities, schools, businesses, and residents along the pipeline right-of-way.

(D) The program and media used must be as comprehensive as necessary to reach all areas in which the pipeline operator shall transport gas.

(7) Each pipeline operator shall establish procedures for analyzing accidents and failures for the purpose of determining the cause of the failure and minimizing the possibility of subsequent reoccurrence.

(8) Each pipeline operator shall not operate any natural gas pipeline at a pressure that exceeds the documented pressure at which the natural gas pipeline may be safely operated.

(9)(A) Each pipeline operator shall have a patrol program to observe surface conditions on and adjacent to its pipeline right-of-way for indications of leaks, construction activity, erosion, condition of signage, conditions at public road and railroad crossings, and other factors affecting safety and operation of the pipeline.

(B) Patrols shall be conducted and documented at least twice each calendar year, not to exceed seven and one-half (7 1/2) months between patrols.

(10)(A) Each pipeline operator shall maintain appropriate pipeline markers at all public road and railroad crossings and along the pipeline at intervals necessary to identify the location of the buried pipeline.

(B) The marker should include the words “Warning”, “Caution”, or “Danger” followed by the words “Gas Pipeline” along with the pipeline operator’s name and telephone number where the pipeline operator can be reached at all times.

(11) Each pressure relieving device in a compressor station, pressure limiting station, or regulator station must be inspected, tested, and operated at the pipeline’s maximum operating pressure once each calendar year and not to exceed fifteen (15) months to determine proper operation.

(12) Each remote controlled shutdown device must be inspected and tested once each calendar year and not to exceed fifteen (15) months to determine proper operation.

(13) Each line valve that serves to block a segment of pipeline and/or might be used in an emergency, must be inspected and partially operated once each calendar year and not to exceed fifteen (15) months.

(14) Each pipeline operator shall maintain records associated with operation and maintenance of the pipeline required in this section.

(15)(A) Each natural gas pipeline abandoned in place must be disconnected from all sources of gas, purged of gas, filled with freshwater or inert material, and sealed at both ends.

(B) When a pipeline is being purged, all efforts must be taken to:

(i) Prevent the formation of a hazardous mixture of gas and air;

(ii) Ensure that all safety equipment necessary is present;

(iii) Remove all nonessential persons from the area; and

(iv) Ensure the public is adequately protected.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: (Order No. 90-97) October 28, 1997; amended December 16, 2007; amended September 14, 2008; amended October 24, 2009; amended January 20, 2014)" Authorities: Arkansas Code § 15-71-110; Arkansas Code § 15-71-117

15 CAR § 275-407 Authority to commingle {#sec-15-car-275-407 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-407}

15 CAR § 275-407. Authority to commingle.

(a)(1) This section authorizes the Director of Production and Conservation or his or her designee to approve certain commingle requests as detailed in this section.

(2) This section:

(A) Is applicable for administrative approval of commingling of multiple common sources of supply on an individual well basis only; and

(B) Includes previously completed and/or uncompleted sources of supply in a well, with no restriction on rate of production.

(3) The section is not applicable on a field-wide basis.

(b)(1) All common sources of supply classified by the Oil and Gas Commission as uncontrolled are:

(A) Exempt from the provisions of this section; and

(B) Permitted to be commingled without application, only when commingled with other uncontrolled sources of supply.

(2) Upon completion of the commingling activities, reporting in accordance with 15 CAR § 275-205 is required.

(c) All common sources of supply previously approved and commingled in wells before the effective date of this section are allowed to continue in effect for the life of the well.

(d)(1) Commingling is permitted without application for the Middle Atoka, as defined by 15 CAR § 275-231(a)(2).

(2) Upon completion of commingling activities, reporting in accordance with 15 CAR § 275-205 is required.

(e) Requests for the commingling of common sources of supply with a well, or at the surface of a well in the following well categories, are not subject to the administrative approval process set forth in this section, and must be brought before the commission for approval following proper notice and hearing:

(1) A wildcat well;

(2) A well located within an exploratory unit established by commission order;

(3) A well in which the commingling of multiple common sources of supply will result in an unapproved additional completion within the drilling unit;

(4) A well in which the primary reservoir drive mechanism for a requested zone to be commingled is a water drive;

(5) A well in which the ownership between the commingled zones is not common, unless all owners, as defined in Arkansas Code § 15-72-102(9), in the well agree in writing; or

(6) A well in which spacing requirements are different between commingled zones.

(f) Application to commingle common sources of supply in accordance with this section shall be submitted on a form prescribed by the director and shall include, at a minimum:

(1) The operator’s contact information;

(2) The name and location of the well;

(3) The perforated intervals to be commingled;

(4) A plat showing well locations in the unit indicating all common sources of supply to be commingled;

(5) A statement as to whether the primary reservoir drive mechanism for the requested commingled zone is a water drive;

(6) A statement as to whether all zones to be commingled have common spacing requirements;

(7) A statement as to whether any of the requested zones to be commingled are subject to a location exception order, the penalty for which will be applied to the commingled production; and

(8) Proof of notice sent to all offset operators of the right to drill and produce in all adjacent units, of the intent to commingle.

(g)(1) Upon review and approval of the application and if no objections are received by the director within fifteen (15) days of the date of the notice sent to each adjacent offset operator, or if the application is accompanied by written acceptance by the offset operators of the commingle request, the application for commingling shall be approved.

(2) Approved applications are only valid for one (1) year from date of issuance, unless commingling activities have been commenced prior to that time.

(h) Following approval of the commingle application, the applicant shall submit to the director the following:

(1) Completed Well Completion and Recompletion Report; and

(2) Rates and pressures for each commingled zone, unless a staged frac completion technique has been used in the well.

(i) If the director receives an objection to a commingle application during the notice period specified subsection (f) of this section, above, or if the application does not satisfy the requirements of this section and is denied by the director, the applicant may request to have the matter placed, in accordance with 15 CAR §§ 275-101 and 275-102, and other established procedures, on the docket of a regularly scheduled commission hearing.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: new rule February 2, 2006; amended January 22, 2009; amended June 5, 2009)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-408 Additional completions within common sources of supply within a drilling unit {#sec-15-car-275-408 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-408}

15 CAR § 275-408. Additional completions within common sources of supply within a drilling unit.

(a) This section is applicable for administrative approval by the Director of Production and Conservation of additional completions within common sources of supply within established drilling units located in fields covered by field rules.

(b) This section is not applicable on a field-wide basis, or within exploratory units.

(c) Application for additional completions shall be submitted to the director on a form prescribed by the director, and contain the following information:

(1) The location of the unit;

(2) The location of all well or wells showing the productive zones in each well within the unit for which the additional completions are requested;

(3) Initial and current pressures and current rates and cumulative production for each completion within a common source of supply;

(4) A structure and isopach map of the common source of supply;

(5) A unit cross-section, including the wells for which the additional completion is requested;

(6) A statement as to whether there is common ownership within the wells producing from the common source of supply within the unit; and

(7) If applicable, the drainage characteristics for each well within the common source of supply.

(d) In addition, each application shall provide proof of written notice to all owners, as defined in Arkansas Code § 15-72-102(9), in the subject unit and all offset operators in all adjacent established units including all owners, as defined by Arkansas Code § 15-72-102(9), in any offset unit where the operator is the same as the applicant.

(e) The notice shall contain at a minimum, the name of the applicant, the name and location of the well, the zone subject to the additional completion request, and instructions as to the filing with the director written objections within fifteen (15) days after receipt of the application by the director.

(f) Any offset operator or owner noticed in accordance with subsection (e) of this section, above, shall have the right to object to the granting of such application within fifteen (15) days after receipt of the application by the director.

(g) Upon review of the application, and if the submitted evidence or requested additional evidence indicates that:

(1) Stratigraphic or structural separation of the common source of supply can reasonably be demonstrated; or

(2) The irregular shape and/or size of the drilling unit relative to the drainage characteristic of the well within the common source of supply necessitate an additional completion; or

(3) The drainage characteristics of the well within the common source of supply in a regular shape and size drilling unit demonstrate an additional completion is necessary to effectively drain the unit; or

(4) The pressure data from the common source of supply indicates less than a twenty percent (20%) reduction in the original pressure five (5) years after the first completion in that same source of supply; or

(5) The other unit completions in the common source of supply have each produced less than seventy-five (75) Mcf per day over the twelve-month period prior to the additional completion application or a newly drilled well, which is the subject of the additional completion request, and which is only able to produce less than seventy-five (75) Mcf per day absolute open flow; and

(6) If ownership within the wells in the common source of supply within the unit is not common, but evidence of agreement between the owners is provided with the additional completion application; and

(7) If an objection is not received within fifteen (15) days after the receipt of the application, the director shall approve the application.

(h)(1) If an objection is received or if the application does not satisfy the requirements of this section, the application shall be denied.

(2) If an application is denied, or if the reason for an additional completion request is not addressed by this section, the applicant may request to have the matter placed, in accordance with established procedures, on the docket of a regularly scheduled Oil and Gas Commission hearing.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: new rule February 2, 2006; amended April 13, 2008)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-409 Noise level requirements for nonwellhead compressor facilities {#sec-15-car-275-409 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-409}

15 CAR § 275-409. Noise level requirements for nonwellhead compressor facilities.

(a) Applicability.

(1) The provisions of this section apply to all nonwellhead compressor facilities or stations used in the production process, as defined in Arkansas Code § 15-71-110, as amended, or whose owner is not affiliated with an Arkansas natural gas public utility and the majority owner is either a production company or an affiliate of a production company.

(2) All nonwellhead compressor facilities in operation as of the initial effective date of this section shall be in compliance with the provisions of this section by July 1, 2012.

(3) All nonwellhead compressor facilities that become operational after the initial effective date of this section shall be in compliance with the provisions of this section within one (1) year of commencing compressing operations.

(b) Definitions. As used in this section:

(1) “ANSI” means the American National Standards Institute, and any reference to an ANSI publication shall refer to the version that was in effect as of January 1, 2011, unless otherwise stated;

(2) “Leq” means the equivalent continuous sound level which is the notional sound pressure level which, if maintained constant over a given time, delivers the same amount of acoustic energy at some point as the time-varying sound pressure level would deliver at the same point and over the same period of time;

(3) “Noise sensitive area" means a building with an established mailing address that is being utilized as:

(A) A private residence;

(B) A school;

(D) A church;

(E) A nursing home; or

(F) An other building of a type that is regularly used for overnight accommodation;

(4)(A) “Nonwellhead compressor facility or station” means any compressor facility or station used for the purpose of compressing natural gas for pipeline transportation.

(B) This shall not include a compressor facility or station located on a well pad for the purpose of enhancing production of natural gas from the well or wells located on the pad; and

(5) “Normal full-load operating conditions” means the normal operating condition of the nonwellhead compressor facility or station, excluding accidents, emergency situations, other unforeseen temporary operational deviations, including without limitation the performance of maintenance or construction activities.

(c) The noise levels for a nonwellhead compressor facility or station during normal full-load operating conditions shall not exceed fifty-five (55) dB(A) Leq, as measured from the exterior of the nearest noise sensitive area existing at the time of commencement of initial construction of the nonwellhead compressor facility or station.

(d) Noise levels shall be measured as follows:

(1) By utilizing a Type 1 sound level meter, as defined in ANSI S1.4, set for A-weighting per ANSI S1.11, and slow meter response;

(2) Sound level measurements shall be in substantial compliance with standard environmental acoustical measurement practices as outlined in ANSI S12.9; and

(3)(A) The Leq contribution due to a nonwellhead compressor facility or station shall be determined using short-term sound level averages taken during periods with minimal audible intrusion from extraneous sources other than the nonwellhead compressor facility or station under test.

(B) The following extraneous noise shall be excluded from the measurements to the fullest extent possible:

(i) Wind;

(ii) Vehicular traffic;

(iii) Residential heating, ventilating, and air conditioning;

(iv) Aircraft over-flights;

(v) Bird sounds;

(vi) Insect sounds; and

(vii) Other noise generating equipment unrelated to the nonwellhead compressor facility or station.

(e)(1) Any owner or operator of a nonwellhead compressor facility or station found to be in violation of the provisions of this section shall pursue with reasonable diligence a remedy to correct the violation.

(2) Any violation shall be considered an operational violation in accordance with 15 CAR § 275-104.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: new rule November 1, 2011)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-410 Procedures for determining the production allowable for dry natural gas production wells {#sec-15-car-275-410 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-410}

15 CAR § 275-410. Procedures for determining the production allowable for dry natural gas production wells.

(a) Applicability.

(1) This section shall only apply to dry natural gas wells for which it is necessary to determine the PRU deliverability in accordance with 15 CAR §§ 275-230 and 275-231, and other applicable general rules, field rules, or commission orders.

(2) This section shall not apply to any PRU subject to provisions of 15 CAR § 275-232.

(b) Definitions. As used in this section:

(1) “Allowable” means the PRU deliverability for a new or existing PRU is allowed to produce and sell on a per day basis;

(2) “Encroachment footage” means the actual footage of the new or existing PRU from the drilling unit boundary, when that footage is less than the setback footage specified by rule;

(3) “Existing PRU” means a production reporting unit, which is either an individual producing zone or approved commingled producing zones within a dry natural gas well which was previously productive prior to the effective date of this section;

(4) “FUB” means distance from a drilling unit boundary line;

(5) “New PRU” means a production reporting unit, which is either an individual producing zone (in a newly drilled dry natural gas well or a new zone in an existing dry natural gas well), or approved commingled producing zones within a dry natural gas well which becomes productive after the effective date of this section;

(6) “Penalty allowable” means the PRU deliverability of the new or existing PRU, subject to a penalty factor, a new or existing PRU is allowed to produce and sell on a per day basis;

(7) “Penalty factor” means the factor which is multiplied by the new or existing PRU to impose a penalty (or reduction) upon the PRU deliverability;

(8) "PRU deliverability" means the measured volume of dry natural gas from an existing or new PRU under normal operating conditions for that existing or new PRU as determined by the IOPT or production test conducted in accordance with 15 CAR § 275-405; and

(9) “Setback footage” means the required minimum distance a new or existing PRU must be from the drilling unit boundary.

(c) Any new or existing PRU, not subject to a penalty factor in accordance with subsection (d) of this section, below, shall be subject to an allowable as follows:

(1) A new or existing PRU shall have an allowable determined as follows: Allowable = PRU Deliverability x (proposed drilling unit acreage ÷ 640 acres or applicable established drilling unit acreage); and

(2)(A) A new or existing PRU with a PRU deliverability of less than seventy-five (75) MCFD shall have an allowable determined as follows: Allowable = 75 MCFD.

(B) PRU deliverability of less than seventy-five (75) MCFD shall be demonstrated by either:

(i) Conducting a test utilizing the methodology specified in 15 CAR § 275-405; or

(ii) Utilizing the most recent six-month average daily rate of production for the PRU under actual operating conditions calculated by dividing the total gas reported by the number of days produced during the applicable six-month period.

(d) Any new or existing PRU subject to a penalty allowable, the penalty allowable shall be determined as calculated as follows:

(1) If the encroachment footage encroaches upon only one (1) boundary of said drilling unit, the penalty allowable shall be the greater of seventy-five (75) MCFD or calculated as follows:

Penalty Allowable = PRU Deliverability x Penalty Factor (Encroachment Footage ÷ Setback Footage) x proposed drilling unit acreage ÷ 640 acres or applicable established drilling unit acreage

Penalty Allowable = PRU Deliverability x Penalty Factor [(1^st Encroachment Footage + 2nd Encroachment Footage) ÷ Setback Footage -1] x proposed drilling unit acreage ÷ 640 acres or applicable established drilling unit acreage

(e) Sales in excess of the penalty allowable.

(B) The shut-in period shall be determined by dividing the excess sales by the penalty allowable.

(A) A civil penalty not to exceed two thousand five hundred dollars ($2,500) per day for every day the PRU produced beyond the thirty-day period; and

(B) Further enforcement actions in accordance with 15 CAR § 275-104, and Arkansas Code §§ 15-72-401 — 15-72-406.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: new rule August 01, 2014)" Authorities: Arkansas Code § 15-71-110; Arkansas Code § 15-72-103; Arkansas Code § 15-72-401

15 CAR § 275-411 Requirements for lease rights gas supply lines {#sec-15-car-275-411 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-411}

15 CAR § 275-411. Requirements for lease rights gas supply lines.

(a) Definitions. As used in this section:

(1) “Director” means the Director of Production and Conservation;

(2) “Existing lease rights gas supply line” means a pipeline under jurisdiction of the Oil and Gas Commission as defined in Arkansas Code § 15-71-110, which:

(A) Transports natural gas from a well operator connection located at a natural gas well, or other natural gas production equipment located upstream of the production meter on the well location, to an end user; and

(B) Was constructed before the initial effective date of this section, January 15, 2015;

(3) “New lease rights gas supply line” means a pipeline under jurisdiction of the Oil and Gas Commission as defined in Arkansas Code § 15-71-110, which transports natural gas from a well operator connection located at a natural gas well, or other natural gas production equipment located upstream of the production meter on the well location, to an end user, and was constructed after the effective date of this section, January 15, 2015;

(4) “Lease rights gas supply line operator” means a lease rights gas supply line owner who:

(A) Has an agreement authorizing natural gas supply;

(B) Accesses directly from the well operator connection; and

(C) Owns or operates and is responsible for the construction, operation, and maintenance of a lease rights gas supply line;

(5) “Lease rights gas” means the gas owned and controlled by the lease rights gas supply line operator once it passes the well operator connection; and

(6) “Well operator connection” means the point at which the operator provided access point connects to the lease rights gas supply line, and at which point the control of the gas by the well operator terminates and is assumed by the lease rights gas supply line operator.

(b) All existing and new lease rights gas supply lines located downstream of a production meter at the natural gas well or other natural gas production equipment located on the well location, and which is under the jurisdiction of the commission as defined in Arkansas Code § 15-71-110, are not subject to the provisions of this section, but shall be subject to all other applicable federal regulations and state rules governing natural gas pipelines.

(c) All new lease rights gas supply lines originating at a well operator connection are subject to the following provisions:

(1)(A) Utilizing the services of a plumber licensed by the State of Arkansas, the new lease rights gas supply line operator shall properly install one (1) or more properly sized regulator or regulators on the lease new rights gas supply line at the well operator connection point and all necessary piping to accommodate appropriate odorization, gas utilization metering equipment, and a properly sized regulator at the dwelling or structure where the natural gas is utilized.

(B) All materials used shall be designed for natural gas service and provide structural integrity where necessary;

(2) Utilizing the services of a plumber licensed by the State of Arkansas, the new lease rights gas supply line operator shall properly install an excess flow valve on the new lease rights gas supply line as close to the well operator connection as feasible;

(3) Utilizing the services of a plumber licensed by the State of Arkansas, the new lease rights gas supply line operator shall properly install appropriate dehydration facilities on the new lease rights gas supply line downstream from the well operator connection, and the well operator shall properly install and maintain odorization facilities upstream of the new lease rights gas supply line;

(4)(A)(i) Utilizing the services of a plumber licensed by the State of Arkansas, new lease rights gas supply lines shall be constructed of steel or plastic that is:

(a) Designed, manufactured, and intended for natural gas service in accordance with industry standards; and

(b) Is tested and free of leaks prior to placing into service.

(ii) Each test shall be at a pressure of fifty pounds per square inch gauge (50 psig) for a period of thirty (30) minutes.

(iii) All piping shall be installed in a manner which will minimize strain or external loading.

(iv) If plastic pipe is used, it shall be installed so as to minimize tensile stresses and must have a tracer wire or means of locating the pipe while underground.

(v) Tracer wire may not be wrapped around the plastic pipe and contact with the pipe should be avoided with at least two inches (2”) between the wire and the lease rights gas supply line.

(B) All new lease rights gas supply lines shall be buried and have a minimum of eighteen inches (18”) of cover or greater if necessary to not pose a safety hazard to surface activities conducted along the lease rights gas supply line right-of-way.

(C) All repairs or relocation of a new lease rights gas supply line must be performed by a plumber licensed by the State of Arkansas and be in accordance with all applicable above provisions;

(5) Install and maintain signage within the line of sight along the new lease rights gas supply line, with such signs to include words one inch (1”) in height and one-fourth inch (1/4”) in stroke “WARNING – DANGER – NATURAL GAS PIPELINE”, and including the name, address, and twenty-four-hour contact information of the new lease rights gas supply line operator; and

(6)(A) Provide the director or his or her designee and the well operator written notification of the name, address, and telephone number that should be used to notify the new lease rights gas supply line operator of any emergency condition.

(B) The new lease rights gas supply line operator shall ensure that this information is kept current with the director or his or her designee and the operator.

(d)(1) For all existing lease rights gas supply lines, the well operators providing a well operator connection shall provide the director with a list of names and addresses of the legally entitled recipients of the lease rights gas, as reflected in the records of the well operator.

(2) The director shall send a letter to each existing lease rights gas supply line operator notifying them of the requirements of this section.

(3) Within six (6) months from the date the notification letter was sent, all existing lease rights gas supply line operators shall document compliance with subdivisions (d)(4)(A) — (F) of this section, below, by the submission of documentation to the director or his or her designee.

(4) If the existing lease rights gas supply line operator fails to demonstrate compliance with subdivisions (d)(4)(A) — (F) of this section, or if the existing lease rights gas supply line operator fails to comply with subdivisions (d)(4)(A) — (F) of this section, the director or his or her designee may authorize the operator to disconnect the lease rights gas supply line until such time as the existing lease rights gas supply line operator is in full compliance with the following:

(A) The lease rights gas supply line operator shall affirm that the existing lease rights gas supply line is:

(i) Constructed of steel or plastic that is designed, manufactured, and intended for natural gas service in accordance with industry standards, that all piping was installed in a manner which will minimize strain or external loading, and is free of leaks; and

(ii) Buried and have at least a minimum of eighteen inches (18”) of cover or greater if necessary so as not to pose a safety hazard to surface activities conducted along the lease rights gas supply line right-of-way;

(B)(i) The lease rights gas supply line operator shall also affirm that all plastic piping has a tracer wire installed with the piping, or other means of locating the pipe underground.

(ii) Tracer wire may not be wrapped around the plastic pipe and contact with the pipe should be avoided with at least two inches (2”) between the wire and the lease rights gas supply line.

(iii) Tracer wire or other means of locating the pipe underground is required when the existing lease rights gas supply line:

(a) Crosses public or private roads or creeks;

(b) Crosses any property not owned by the lease rights gas supply line operator; or

(i) One (1) or more properly sized regulators on the lease rights gas supply line at the well operator connection; and

(ii) An excess flow valve as close to the well operator connection as reasonably possible;

(D) All repairs or relocation of an existing lease rights gas supply line must be performed by a plumber licensed by the State of Arkansas and be in accordance with all applicable above provisions;

(E) Existing lease rights gas supply line operators shall install and maintain signage within the line of sight along the existing lease rights gas supply line, with such signs to include words one inch (1”) in height and one-fourth inch (1/4”) in stroke “WARNING – DANGER – NATURAL GAS PIPELINE”, and include the name, address, and twenty-four-hour contact information of the lease rights gas supply line operator;

(F)(i) Existing lease rights gas supply line operators shall provide the director or his or her designee and the operator written notification of the name, address, and telephone number that should be used to notify the lease rights gas supply line operator of any emergency condition.

(ii) The lease rights gas supply line operator shall ensure that this information is kept current with the director or his or her designee and the operator; and

(G) The well operator shall properly install and maintain odorization facilities upstream of the lease rights gas supply line.

(e)(1) Produced fluids collected by the new or existing lease rights gas supply line operator shall be removed from the site and disposed in accordance with applicable commission and Division of Environmental Quality rules.

(2) Produced fluids shall not be discharged onto the ground surface or into waters of the state.

(3) Any spill of produced fluids shall be remediated in accordance with applicable commission and division rules.

(f)(1) Unless otherwise authorized in the agreement authorizing the natural gas supply, all existing lease rights gas supply lines servicing multiple domestic or end users are prohibited, and within six (6) months from the date the notification letter was sent in accordance with subsection (d) of this section, above, the lease rights gas supply line operator shall reconfigure the lease rights gas supply line to only allow for a single domestic or end user per lease rights gas supply line.

(2) Unless otherwise authorized in the agreement authorizing the natural gas supply, new lease rights gas supply lines shall only allow for a single domestic or end user per lease rights gas supply lines.

(g)(1) All lease rights gas supply line operators shall maintain compliance with the provisions of this section.

(2) If a lease rights gas supply line operator fails to comply with the provisions of this section, the director or his or her designee shall give notice of the violation in accordance with 15 CAR § 275-104, to the lease rights gas supply line operator.

(3) The lease rights gas supply line operator shall have thirty (30) days to comply with the notice of violation.

(4) If the lease rights gas supply line operator fails to comply or properly request a review or appeal in accordance with 15 CAR § 275-104, then the director or his or her designee may authorize the operator to disconnect the lease rights gas supply line until such time as the lease rights gas supply line operator is in full compliance with the provisions of this section.

(5) Any appeal of a director’s decision for a notice of violation issued in accordance with this subsection (g) shall not be subject to the filing fee required in accordance with 15 CAR §§ 275-101 and 275-102.

(h) Lease rights gas supply line operators are no longer subject to the provisions of this section if the well where the well operator connection is located is transferred to the lease rights gas supply line operator in accordance with 15 CAR § 275-211.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: new rule January 15, 2015; amended March 1, 2016)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-412 General rule for the regulation of underground natural gas and other gas storage projects {#sec-15-car-275-412 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-412}

15 CAR § 275-412. General rule for the regulation of underground natural gas and other gas storage projects.

(a) Authority and applicability.

(1)(A) The underground storage of gas:

(i) Promotes conservation;

(ii) Permits the building of reserves for orderly withdrawal in periods of peak demand;

(iii) Makes more readily available and economical natural gas resources to the domestic, commercial, and industrial consumers;

(iv) Contributes to a healthier environment; and

(v) Promotes the public interest and welfare of the State of Arkansas.

(B) Therefore, the Oil and Gas Commission may find and determine, in accordance with Arkansas Code § 15-72-603, that the underground storage of gas is in the public interest.

(2)(A) All natural gas public utilities or gas storage facilities engaged in the process of the storage of gas in underground reservoirs within the State of Arkansas, as specified in the Underground Storage of Gas Law, Arkansas Code § 15-72-601 et seq., are subject to the provisions of this section.

(B) This section does not apply to gas injection or withdrawal operations conducted as a part of, or in conjunction with, any secondary or tertiary oil recovery methods utilized in a unitized pool or unit area established by the commission.

(3) Gas storage facilities established by the commission, which were in existence on or before December 21, 2020, are not subject to the provisions contained herein with the exception of subdivision (f)(9) of this section.

(4) All gas storage facilities are subject to the provisions of subsections (c), (d), and (e) of this section unless any provisions contained herein dealing with natural gas storage facilities are less stringent than any applicable federal requirement enumerated in subdivision (f)(9) of this section, or unless any provisions contained herein dealing with carbon dioxide storage wells are in conflict with provisions of the United States Environmental Protection Agency, Underground Injection Control, Class VI Well Program.

(5) The commission retains jurisdiction over the regulation of gas storage.

(b) Definitions. As used in this section:

(1) “Certificate of Storage” means an order issued by the Oil and Gas Commission that:

(A) Identifies an underground stratum or formation that is suitable for the underground storage of gas and that its use for such purposes is in the public interest;

(B) Designates the horizontal and vertical boundaries of the underground storage reservoir, such boundaries to include any necessary or reasonable buffer zone for the purpose of ensuring the safe operation of the storage facility and to protect the underground storage reservoir from pollution or invasion, or escape or migration of gas therefrom;

(D) Designates the storage operator for said facility; and

(E) Adopts special rules for the operation of the facility;

(2) “Commission” means the Oil and Gas Commission;

(3) “Cushion natural gas” means the volume of gas required as permanent storage inventory to maintain adequate reservoir pressure to meet minimum gas deliverability demand (also called “base gas”);

(4) “Gas” means natural gas either while in its original state or after the natural gas has been processed by removal from the natural gas of component parts not essential to its use for light or fuel, or carbon oxides, ammonia, hydrogen, nitrogen, or noble gas;

(5) “Gas storage operator” means any company, person, corporation, partnership, limited partnership, association of persons, municipality, association of municipalities, public utility, gas district, or any other entity engaged in the business of capturing, producing, or storing gas and authorized by the Oil and Gas Commission to operate any UGSF;

(6) “Gas storage reservoir (GSR)” means the same as an “underground storage reservoir (USR)”;

(7) “Gathering line” means a pipeline that transports gas from a current production facility to a transmission line or main;

(8) "Native gas" means gas that has not been previously withdrawn from the earth;

(9) "Natural gas" means all natural gas, casinghead gas, and occluded natural gas found in coalbeds, and all other hydrocarbons not defined as oil in 15 CAR § 275-103, but not including liquid petroleum gas;

(10) "Natural gas public utility" means any person, firm, corporation, or entity engaged in the business of producing, transporting, or distributing natural gas by means of pipelines into, within, or through this state for ultimate public consumption;

(11) “Observation well” means any well drilled or converted for the purpose of monitoring reservoir pressures, temperatures, or integrity of a GSR;

(12) “Storage operations” means the process of injecting gas into a USR;

(13) “Storage well” means any well drilled or converted within a UGSF for the purpose of gas injection and gas withdrawal, but excluding storage wells utilized for storage of carbon dioxide;

(14) “Underground gas storage facility (UGSF)” means a USR, the injection and withdrawal wells and well tubular goods, the wellhead, and related equipment to the last positive shut-off valve before the gathering line that is used or to be used for the underground storage of gas, and all surface and subsurface rights and appurtenances necessary or useful in the operation of the facility for the underground storage of gas, including any necessary or reasonable buffer zone as identified and recommended by the gas storage operator and approved by the Oil and Gas Commission for the purpose of ensuring the safe operation of the storage of gas, and to protect the storage facility against pollution or invasion, or escape or migration of gas therefrom;

(15) "Underground storage" means the storage of gas in a USR;

(16) “Underground storage reservoir (USR)” means any porous subsurface sand, stratum, or formation that is completely separated from any other porous zone and is suitable for, or capable of, being made suitable for the injection and storage and withdrawal of gas; and

(17) “Working natural gas” means the portion of the storage volume that can be removed from a USR for deliveries and still maintain pressure sufficient to meet design deliverability.

(1) Any natural gas public utility or gas storage operator desiring to exercise the right of eminent domain in accordance with Arkansas Code § 15-72-606 to acquire or take any property for the underground storage of gas, shall first obtain from the commission a Certificate of Storage setting forth the following:

(A) The amount of recoverable oil and native gas, if any, remaining in the USR and a determination as to proper allocation of that amount;

(B) That the property to be taken or acquired is suitable for the underground storage of gas; and

(2) The natural gas public utility or gas storage operator shall present to the circuit court of the county wherein the land is situated, or to the judge thereof, a petition setting forth:

(A) The purpose for taking the property;

(B) A legal description of the property to be taken; and

(3) The petitioner shall file the Certificate of Storage issued by the commission as a part of its petition, and no order by the court granting the petition shall be entered without the Certificate of Storage being filed therewith.

(d) Issuance of Certificate of Storage.

(1) Any natural gas public utility or gas storage operator may file an application to have the commission issue a Certificate of Storage for the storage of gas in a USR.

(2)(A) The commission shall publish a notice at least once each week for two (2) successive weeks in a newspaper of general circulation in the county or counties where the proposed UGSF is to be located.

(B) The first publication of the notice must be at least ten (10) days prior to the date of the hearing.

(3) Only the area of the USR that may reasonably be expected to be penetrated by gas displaced or injected into the USR, as determined by the commission, may be covered by the Certificate of Storage.

(4) The Certificate of Storage granted in this section shall not prejudice the rights of the owner or owners of the lands, or of other rights or interests therein:

(A) To drill or bore through the USR as established by rules of the commission; and

(B) As to all other uses of the lands not inconsistent with the operation of the UGSF.

(5)(A) All gas which has been reduced to possession and which is subsequently injected into a USR shall at all times be deemed the property of the gas storage operator or his or her heirs, successors, or assigns.

(B) This gas shall not be in any manner subject to the right of the surface owner of the lands or the owner of any mineral interest under or above the UGSF, or subject to the right of any other person or entity.

(C) The gas storage operator or his or her heirs, successors, and assigns have the sole and only right to produce, take, or reduce to possession this gas in the USR, and no other person may waste or otherwise interfere with or exercise any control over the USR or any gas therein.

(D) The gas storage operator or his or her heirs, successors, and assigns shall have no right to gas in any other underground reservoir that is not subject to the Certificate of Storage.

(6)(A) After notice and hearing, the commission may issue a Certificate of Storage if it affirmatively finds, based upon substantial evidence, that the proposed USR is geologically suitable and has a greater value or utility as a USR for the purpose of ensuring an adequate supply of natural gas for any particular class or group of consumers of natural gas, or for the storage of gas, than for the production of relatively small volumes of native gas which may remain therein.

(B) The commission shall not issue a Certificate of Storage if the proposed USR is capable of producing oil, in paying quantities, through any known recovery method, or is a USDW as defined in 15 CAR § 275-801.

(e) Contents of application for Certificate of Storage.

(1)(A) No UGSF shall be constructed or operated without the gas storage operator obtaining or holding the necessary and sufficient property rights for construction and operation of the UGSF.

(B) The gas storage operator shall provide evidence of holding such rights for any real or personal property, or evidence the gas storage operator can obtain such property through eminent domain proceedings related to that property.

(C) A Certificate of Storage shall expire twelve (12) months from the date of issuance if the storage wells have not been drilled and completed, or within twenty-four (24) months if the storage wells have been drilled and completed and if storage operations have not commenced.

(2) Application for a Certificate of Storage shall include the following:

(A) A plan view map showing:

(i) The surface and extent of the UGSF, indicating the proposed location of storage wells, observation wells, and the location of all proposed pipelines and other surface facilities within the boundary of the UGSF;

(ii) Locations of all other wells or boreholes, including but not limited to, water wells, and oil and natural gas exploration and development wells within the boundary of the UGSF and extending one-quarter (1/4) mile outside the boundary of the UGSF; and

(iii) The subsurface extent of the USR and any buffer zone;

(B) Applicant shall submit evidence or information showing that the proposed USR is not a USDW and identify any freshwater bearing horizons known to be developed in the immediate vicinity of the USR;

(C) Applicant shall conduct an evaluation to identify any productive oil and natural gas zones occurring stratigraphically above, below, or within the USR, and if productive natural gas zones are present within the USR, the applicant shall identify and determine the remaining reserves of native gas within the USR;

(D) A geologic evaluation of the USR, including:

(i) An isopach map of the USR;

(ii) A structure map of the top and base of the USR;

(iii) Identification of all structural spill points or stratigraphic discontinuities controlling the isolation of stored gas; and

(iv) A structural and stratigraphic cross-section that describes the geologic conditions of the USR;

(E)(i) A geologic evaluation of all existing information on all geologic strata overlying the USR, including the immediate containment formation (caprock) characteristics and all designated subsurface monitoring zones.

(ii) The evaluation shall focus on the proposed USR and provide a description of mechanisms of geologic confinement with regard to the ability of that confinement to prevent migration of gas beyond the proposed USR.

(iii) The evaluation shall 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 which may impact confinement;

(F)(i) A review of all wells within the proposed USR which penetrate the USR or primary and/or secondary confining layers overlying the USR and all the wells within one (1) mile of the USR which penetrate the geologic formation to be used for storage.

(ii) This review shall determine:

(a) If all abandoned wells have been plugged; and

(b) Whether all unplugged wells are constructed in a manner that prevents the movement of gas from the USR;

(G)(i) The proposed calculated maximum volume of the USR to be used for storage shall include working natural gas, native gas, and cushion natural gas volumes.

(ii) In the event the storage operator of a UGSF recalculates the actual reservoir volume determined and identified to the commission after continued operation of the gas storage facility, then the gas storage operator shall file an application for a redetermination of the allowed volume;

(H)(i) The proposed maximum bottom-hole injection pressure to be utilized for the USR shall be measured in pounds per square inch gauge (psig) and shall be no greater than ninety percent (90%) of the formation fracture pressure as determined by a step-rate test or other approved method, unless a higher percentage is approved by the commission.

(ii) The USR shall not be subjected to injection pressures in excess of the calculated fracture pressure.

(iii) The maximum allowable stabilized reservoir pressure (gauge) shall be no greater than seventy-five percent (75%) of the fracture pressure of the USR, as determined by a step-rate test or as calculated by a method acceptable to the commission.

(iv) The average USR pressure shall be no greater than ninety percent (90%) of the fracture pressure;

(I) A corrosion monitoring and prevention plan for all wells and surface facilities and a leak detection and monitoring plan for surface facilities and wells which shall include subsurface observation wells to monitor any movement of gas from the USR;

(J)(i) A detailed description of the proposed public safety and emergency response plan.

(ii) The response plan shall detail the safety procedures concerning the UGSF and any residential, commercial, and public land use within one (1) mile, or any other distance as deemed necessary by the commission beyond the outside boundary of the UGSF.

(iii) The plan shall include contingency plans should gas leak from any well, flow line, or any other UGSF.

(iv) These emergency response procedures should be updated as necessary throughout the operational life of the UGSF; and

(K)(i) Authority to conduct an injectivity test, step-rate test, or other injection test to determine the suitability of the USR, prior to the issuance of the Certificate of Storage.

(ii) This authority may be approved by the Director of Production and Conservation upon issuance of the test well permit in accordance with subdivision (f)(1) of this section.

(iii) The director shall establish the parameters of the test for the protection of public safety, the USDW, and any oil and gas resources potentially impacted by the test, and may require the submission of any information or test data deemed necessary.

(f) Natural gas storage wells.

(1) Permitting natural gas storage wells.

(A)(i) No person shall drill, deepen, reenter, recomplete, or operate any storage or observation well until a Certificate of Storage and applicable well permits have been issued by the commission, application for which shall be made on forms prescribed by the director.

(ii) Permits are valid only for the permit holder stated on the permit, and shall remain valid only if the permit holder is in compliance with established operating requirements specified in this section.

(iii) Permits to drill, deepen, or reenter shall automatically expire six (6) months from the date of issuance, unless commencement of the drilling, deepening, or reentry of plugged well operations authorized by the permit has occurred and are continued with due diligence, but not to exceed one (1) year from the date of commencement of the drilling, deepening, or reentry of plugged well operations authorized by the permit.

(iv) If the activity authorized in the permit is not completed within one (1) year, the well shall be plugged, casing set, or a new permit application, along with a new permit fee and plat, must be filed.

(v) Failure to comply with the operating requirements in this section may result in revocation of the storage or observation well permit in accordance with 15 CAR § 275-201(c).

(B)(i) No storage well or observation well may be drilled at a surface location other than that specified on the permit.

(ii) However, if a permit holder has commenced drilling operations and the storage or observation well is lost due to adverse drilling conditions prior to surface casing being set, the permit holder may request an amendment of the permit without a fee for the new location, provided the storage or observation well remains on the same property where the storage or observation well was originally permitted, and all other aspects of the permit request remain the same.

(iii) Movement of the storage or observation well location off the original surface owners’ property, or after surface casing has been set, will require the filing of a new permit application, along with a new permit fee and plat.

(iv) Drilling may not commence prior to the issuance of a new permit.

(C) Upon issuance of a permit, a copy of the permit shall be displayed at the site where the storage well or observation well is being drilled for review by commission staff.

(D) The application to drill, deepen, reenter, or recomplete a storage well or observation well shall include, at a minimum:

(i) The information required by subdivision (f)(1)(F) of this section for the existing or proposed well and any additional information deemed necessary by the director for public safety and the protection of USDWs;

(ii) A permit fee in the amount of three hundred dollars ($300), if the storage well or observation well is drilled, deepened, or reentered;

(iii)(a) The minimum financial assurance of thirty-five thousand dollars ($35,000) per well.

(b) The director is authorized, however, to require additional financial assurance based on, but not limited to:

(1) How long a permit holder has operated in the State of Arkansas;

(2) Environmental consideration of the well location;

(3) Other factors impacting the cost of plugging the well and restoring the associated well site; and

(4) The compliance history of the permit holder.

(iv) A Form 1 Organizational Report in accordance with 15 CAR § 275-212;

(v) An oath that the application is executed under penalty for perjury;

(vi)(a) If the applicant is a corporation, limited liability company, limited liability partnership, or other business entity, it must be incorporated, organized, or authorized to do business in the State of Arkansas.

(b) The applicant must state that by filing an application, the applicant irrevocably waives, to the fullest extent permitted by law, any objection to the jurisdiction of the commission or to a hearing before the commission, or in a court of competent jurisdiction in the State of Arkansas; and

(vii)(a) If the applicant is an individual, partnership, or other entity that is not domiciled in the State of Arkansas, the applicant must be authorized to do business in the State of Arkansas.

(b) By filing an application, the applicant irrevocably waives, to the fullest extent permitted by law, any objection to the jurisdiction of the commission or to a hearing before the commission or in a court of competent jurisdiction in the State of Arkansas.

(E)(i) If the application does not contain all of the required information or documents, the director shall notify the applicant in writing.

(ii) The notification shall specify what additional information or documents are necessary for an evaluation of the application and shall state to the applicant that the application will be deemed denied unless the information or documents are submitted within sixty (60) days following the date of notification.

(F) The application for a storage well shall include the following:

(i) On a form prescribed by the director, the applicant shall provide the name, address, phone, fax, and email, if available, of the local or on-site supervisory or field personnel responsible for the storage well;

(ii)(a) A survey plat of the location and ground elevation of the proposed storage well or existing well.

(b) The survey plat shall include all wells within one-quarter (1/4) mile of the proposed or existing well and the current well status of each well;

(iii)(a) The name and the approximate top and bottom elevation, from sub-sea, of the formation, indicating the perforated or open hole interval, into which natural gas will be injected.

(b) If an existing well is to be converted, a geophysical log of the well shall be submitted showing the above information.

(c) For a proposed well, an induction log from a well in the immediate vicinity of the proposed disposal well shall be submitted; and

(iv)(a) A well bore diagram of the proposed or existing well showing casing for the storage well, indicating from the wellhead to total depth of the well, all casings and cementing of casings, tubing and packer setting depth, and all perforations and/or open hole intervals.

(b) If application is for an existing well, a cement bond log shall be submitted with the application, or if submitted after the application is filed, the cement bond log shall be submitted prior to commencement of operations as a condition of the permit.

(G)(i) If the application does not satisfy the requirements of this section, the application shall be denied.

(ii) If the application is denied under this section, the applicant may request to have the application referred to the commission for determination in accordance with 15 CAR §§ 275-101 and 275-102, and other applicable hearing procedures.

(2) New nonstorage wells drilled, reentered, or deepened through a natural gas storage reservoir.

(A) Any new well drilled after December 21, 2020, through the USR within a UGSF for any purpose other than storage shall comply with the casing programs contained in subdivision (f)(4)(A) of this section.

(B)(i) Any new well reentered or deepened after December 21, 2020, through a USR within a UGSF, shall be evaluated for compliance with subdivision (f)(4)(B) of this section.

(ii) Wells not in compliance shall be reworked and cemented, in accordance with subdivision (f)(4)(B) of this section, to achieve the necessary isolation of the USR.

(C) Well plugging requirements of a nonstorage well located within the UGSF area shall be the same as for a storage well as outlined in subdivision (f)(6) of this section, and any other additional requirements in 15 CAR § 275-209.

(3) Existing nonstorage wells located in a natural gas storage reservoir.

(A)(i) Any nonstorage well penetrating a USR in existence on or before December 21, 2020, shall be evaluated to determine adequate isolation of the USR.

(ii) The director may require a cement bond log, cement evaluation log, or other logs to determine adequate isolation of the USR.

(iii) Nonstorage wells which the director has determined do not provide adequate isolation of the USR may be required by the commission, after notice and hearing, to be reworked to properly isolate the USR.

(B) All casing strings or liner strings run in any existing well which extends through the USR shall be cemented in accordance with subdivision (f)(4)(B) of this section.

(4) Natural gas storage well construction, operation, maintenance, and decommissioning requirements.

(A) All storage wells drilled after December 21, 2020, for the purpose of underground storage shall comply with the following requirements:

(i) All casing used in storage wells shall:

(a) Meet American Petroleum Institute standards;

(b) Be rated for the pressures to be encountered during the operational life of the well; and

(ii)(a) All casing strings shall be centralized throughout the intervals to be cemented, and all casings shall be cemented to surface.

(b) Casing set through the USR shall have centralizers placed near the top and bottom of the USR;

(iii)(a) All cement used for casing cement shall meet or exceed current American Petroleum Institute standards or recommended practices.

(b) Cement should be of the appropriate type and class of cement for the intended use and mixed to the appropriate weight.

(d) Cement slurry samples shall be taken and properly labeled and stored by the storage operator for further testing as necessary;

(iv) Surface casing shall be:

(a) Set at a depth of one hundred feet (100’) below any known USDW within one-half (1/2) mile of the UGSF, or at a depth of five hundred feet (500’), whichever is greater; and

(b) Cemented with a minimum of one hundred fifty percent (150%) of the calculated annular volume to circulate cement to the surface; and

(v) All wells shall be completed with tubing and packer.

(B) Any nonstorage well converted for the purpose of underground storage shall comply with the following requirements:

(i) The top of cement and the degree of bonding of the cement used to anchor the existing production casing or liner string shall be verified by cement bond log, cement evaluation log, or other logs approved by the director;

(ii) The injection of natural gas shall not result in the movement of natural gas or other fluids into a USDW, or other oil or natural gas reservoir;

(iii) New casing liners shall be cemented with sufficient volume to fill the annular space to the surface; and

(iv) All wells shall be completed with tubing and packer.

(5) Mechanical integrity requirements for new and existing natural gas storage wells.

(A)(i) Each storage operator of a storage well equipped with a tubing and packer completion shall prove mechanical integrity of the well before placing it into service.

(ii) Mechanical integrity shall be demonstrated by pressure testing the annulus to the permitted storage well injection pressure, with a minimum test pressure of five hundred pounds per square inch gauge (500 psig).

(iii) Following successful demonstration of mechanical integrity, the storage well shall be retested at least every three (3) years.

(B)(i) Each storage operator of a storage well not equipped with a tubing and packer completion shall prove mechanical integrity within thirty (30) days after the effective date of this section.

(ii) Mechanical integrity shall be demonstrated by setting a retrievable plug within the production casing at a point fifty feet (50’) above the uppermost perforation, and pressure test the casing up to the permitted storage well maximum injection pressure, with a minimum test pressure of five hundred pounds per square inch gauge (500 psig).

(iii) Following successful demonstration of mechanical integrity, the storage well shall be retested at least every five (5) years.

(C) The pressure test shall be continued for thirty (30) minutes and shall not decrease by more than ten percent (10%) of the initial pressure over the length of the test.

(D)(i) Upon request, the director may approve alternate test methods including tracer survey, temperature survey, gamma ray log, neutron log, noise log, casing inspection log, or a combination of these methods to demonstrate mechanical integrity.

(ii) All mechanical integrity alternate test methods shall be witnessed by a commission representative.

(E)(i) If a storage well fails to demonstrate or maintain mechanical integrity, the well shall be removed from service immediately.

(ii) The storage operator shall notify the commission’s regional office within four (4) hours of any well that fails or loses mechanical integrity.

(iii) The storage operator must take action to isolate the cause of the failure and demonstrate to the director that the well does not pose a threat to a USDW or public safety.

(F) Storage wells which fail to demonstrate mechanical integrity shall be repaired within one hundred eighty (180) days and successfully pass a mechanical integrity test or be plugged.

(6) Monitoring and reporting for natural gas storage wells.

(A)(i) Each storage well shall be monitored on a weekly basis for wellhead and casing annulus pressure.

(ii) All monitoring records shall be retained by the storage operator for five (5) years and be available to commission staff for review upon request.

(B) The operator of the UGSF shall notify the commission regional office of any potential leak discovered within four (4) hours of the discovery of the leak.

(C) The storage operator shall file, on a form prescribed by the director, the monthly volumes of natural gas injected and withdrawn from the USR.

(D)(i) Prior to performing any well servicing activity, cementing, or any wireline logging activities, the storage operator of the UGSF shall provide notice to the commission regional office where the storage well is located so as to allow commission staff to be present to observe the activity.

(ii) Any well servicing which requires the resetting of the packer shall require that an internal mechanical integrity test be conducted in accordance with subdivision (f)(5) of this section prior to recommencement of injection.

(7) Natural gas storage well abandonment.

(A)(i) A well plugging plan shall be filed with the commission regional office thirty (30) days prior to any planned well plugging activity.

(ii) All storage wells shall be plugged in a manner to permanently isolate the USR from all other oil and natural gas reservoirs and any existing USDWs within the UGSF area.

(B) The minimum well plugging requirements are as follows:

(i) The storage well shall be plugged as follows:

(a) Utilizing a cement retainer set fifty feet (50’) above the top perforation in the storage well, adequate cement shall be pushed into the USR to prevent pressure channeling while the subsequent storage well cement plug is setting; and

(b) Following completion of the storage well cementing operation, an additional one hundred fifty feet (150’) of cement shall be placed on top of the cement retainer utilized in the storage well cementing operation;

(ii) If cement is not present on the backside of the production casing at the required plug depths specified in subdivision (f)(7)(B)(i) of this section, cement shall be placed on the backside of the production casing during the storage well plugging operations;

(iii)(a) Following the completion of the storage well plugging operation, a pressure test shall be run on the casing to determine cement integrity.

(b) If the casing fails this test, it shall be repaired and retested prior to the subsequent plugs being set as required in accordance with subdivision (f)(7)(B)(iv) of this section;

(iv) Subsequent plugs shall be set to satisfy the requirements of 15 CAR § 275-209; or

(v)(a) If wellbore conditions preclude the setting of a cement retainer for the storage well plugging operation, an alternative plugging method may be approved or required by the director.

(b) In determining whether to approve an alternative plugging method, the director shall consider the:

(1) Time and cost associated with the alternative plugging method;

(2) Potential for damage to USDWs or other oil or gas reservoirs;

(3) Depth of the reservoir in relation to the depth of the USDWs;

(4) Well construction characteristics; and

(5) Potential for upward migration of wellbore fluids into a USDW.

(8) Decommissioning of underground natural gas storage facility.

(A)(i) The gas storage operator of a UGSF shall file a plan for decommissioning a UGSF six (6) months prior to commencement of the decommissioning activity.

(ii) The plan shall include:

(a) The anticipated date of commencement and final completion of the decommissioning activities;

(b) A detailed plan and timeline for the activities including well plugging operations, equipment removal from the well sites, and all central or remote facilities in the UGSF, abandonment of pipelines, and restoration of property as necessary;

(c) The names and contact information for the persons, consultants, contractors, and firms used in the decommissioning activity; and

(d) The anticipated reservoir pressure at abandonment.

(B) The storage operator shall file a monthly report on the fifteenth of each month indicating the work completed for the preceding month during the decommissioning activity.

(C)(i) At the completion of the decommissioning, the storage operator shall submit a final decommissioning report and termination of storage operations.

(ii) Upon receipt of the final report and completion of a final inspection of the UGSF and all wells and facilities by the commission staff, the storage operator’s Certificate of Storage shall be terminated.

(9) Additional federal requirements for natural gas storage operations.

(A) The UGSF is additionally subject to and required to be in compliance with the following federal requirements, unless the following federal requirements are less stringent than any other applicable requirements of this section.

(B) Required federal requirements are as follows:

(i) Operation and maintenance requirements in 49 C.F.R. pt. 192, as amended;

(ii) Applicable enforcement provisions of 49 C.F.R. pt. 190, as amended;

(iii) Applicable incident and other reporting requirements contained in 49 C.F.R. pt. 191, as amended, and all such reports shall be submitted to the commission; and

(iv) All storage operators of a UGSF shall be subject to the applicable drug and alcohol testing requirements contained in 49 C.F.R. pt. 199, as amended.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: new rule July 2, 2024; amended July 4, 2024)" Authorities: Arkansas Code § 15-71-110; Arkansas Code § 15-72-608

Subpart 5

15 CAR § 275-501 Pipelines, purchasers, and transporters {#sec-15-car-275-501 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-501}

15 CAR § 275-501. Pipelines, purchasers, and transporters.

(a) No carrier by pipeline and no gathering system shall transport oil from any lease or wells if the said pipeline or gathering system has reason to believe the owner or operator of said lease or wells to which it is connected has violated any rule or order of the Oil and Gas Commission or any conservation laws of the state with reference to oil and gas.

(b)(1) No pipeline company shall transport oil from any gathering system which the said pipeline company has reason to believe has violated any rule or order of the commission or any conservation law of this state with reference to oil and gas.

(2) It shall be the duty of the pipeline company to suspend transportation of any oil from said gathering system until such time as such pipeline company is notified in writing by the agent of the commission that the violation on the part of the gathering system has been discontinued and that the gathering system is complying with the rules and orders of the commission and the conservation laws of the State of Arkansas.

(c)(1) In order to carry out the spirit and purposes of this and other rules tending to provide orderly production of crude oil without waste and to give equal opportunity for marketing oil to all operators bringing wells into production in said field, all pipeline companies are hereby directed to make connection of their lines to the lease tanks on properties or leases in rotation as wells are completed, regardless of ownership.

(2) Connections shall be accepted and taken by the pipeline which by geographical location and least expense is the logical connection unless some other line is willing to accept the same.

(3) All wells which are at the present time unconnected shall be given connection by the pipeline to which the same are or may be allocated before the owners of such pipelines make connections to their own wells or wells of affiliated companies.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-502 Reports from oil pipelines, transporters, and storers {#sec-15-car-275-502 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-502}

15 CAR § 275-502. Reports from oil pipelines, transporters, and storers.

(a) Each transporter of oil within the State of Arkansas shall furnish for each calendar month a Transporter’s and Storer’s Monthly Report, containing complete information and data indicated by such form respecting stocks of oil on hand and all movements of oil by pipeline within the State of Arkansas, and all movements of oil:

(1) By watercraft, or by trucks or other conveyances except railroads, from leases to storers or refiners;

(2) Between transporters within the state;

(3) Between storers within the state;

(4) Between refiners within the state; and

(5) Between storers and refiners within the state.

(b) Each storer of oil within the State of Arkansas shall furnish for each calendar month a Transporter’s and Storer’s Monthly Report, containing complete information and data indicated by such form respecting the storage of oil within the State of Arkansas.

(c) The Transporter’s and Storer’s Monthly Report for each month shall be prepared and filed according to instructions on the form, on or before the fifteenth day of the next succeeding month.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-503 Exploration and production fluid gathering, handling, and transportation {#sec-15-car-275-503 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-503}

15 CAR § 275-503. Exploration and production fluid gathering, handling, and transportation.

(a) Definitions. As used in this section:

(1) "Class II fluids" means:

(A) Produced water and/or other fluids brought to the surface in connection with drilling, completion, or fracture treatments, workover or recompletion and plugging of oil, natural gas, Class II or wells that are required to be permitted as water supply wells by the Oil and Gas Commission, enhanced recovery operations, or natural gas storage operations; or

(B) Produced water and/or other fluids from subdivision (a)(1)(A) of this section, which prior to reinjection have been used on site for purposes integrally associated with well drilling, completion or fracture treatments, workover or recompletions or plugging oil, natural gas, Class II or wells that are required to be permitted as water supply wells by the Oil and Gas Commission, enhanced recovery operations, natural gas storage operations, or chemically treated or altered to the extent necessary to make them usable for purposes integrally related to well drilling, completion, workover or recompletions or plugging oil, natural gas, Class II or wells that are required to be permitted as water supply wells by the Oil and Gas Commission, enhanced recovery operations, natural gas storage operations, or commingled with fluid wastes resulting from fluid treatments outlined above, provided the commingled fluid wastes do not constitute a hazardous waste under the Resource Conservation and Recovery Act of 1976, 42 U.S.C. § 6901 et seq.;

(2) "Exploration and production fluid” means crude oil bottom sediments and all Class II fluids, to the extent those fluids are now or hereafter exempt from the provisions of Subtitle C of the Federal Resource Conservation Recovery Act of 1976, Pub. L. No. 94-580;

(3) "Exploration and production fluid transportation system" means any motor vehicle licensed for highway use on a public highway or used on a public highway, that is equipped for either carrying or pulling a transportation tank containing exploration and production fluids, from the point of any fluid generation or collection site to any subsequent off-site:

(A) Storage facility;

(B) Surface disposal facility; or

(4) “Exploration and production fluid transporter” means an operator of an exploration and production fluid transportation system; and

(5) "Transportation tank" means an assembly, compartment, tank, or other container that is used for transporting or delivering exploration and production fluid.

(b)(1) No person shall operate an exploration and production fluid transportation system without an exploration and production fluid transportation system permit.

(2) Application for which shall be made on forms prescribed by the Director of Production and Conservation.

(3) The application shall be executed under penalties of perjury and accompanied by an exploration and production fluid transportation system permit fee in the amount specified below.

(c)(1) If the application does not contain all of the required information or documents, the director or his or her designee shall notify the applicant in writing.

(2) The notification shall specify the additional information or documents necessary to process the application, and shall advise the applicant that the application will be deemed denied unless the additional information or documents are submitted within thirty (30) days following the date of notification.

(d) The application shall, at a minimum, include:

(1) A permit fee of one hundred dollars ($100) per transportation tank;

(2) The name, address, and business and emergency telephone numbers of the proposed exploration and production fluid transporter, including Arkansas contact information if the transporter is located outside of the State of Arkansas;

(3) A brief description of the number and type of transportation tanks to be used in the system, specifying whether transportation tanks will be owned, leased, or otherwise arranged for, and including tank capacity and a manufacturer’s serial number or other identifying number for each transportation tank; and

(4) An entity organizational report on a form prescribed by the director.

(e)(1) If the applicant satisfies all requirements of this section, the director shall issue an exploration and production fluid transportation system permit and permit sticker for each transportation tank.

(2) The exploration and production fluid transportation system permit shall be kept in the Arkansas office of the exploration and production fluid transportation system permit holder.

(3) The permit sticker shall be affixed to the back of the transportation tank and shall be kept visible and readable at all times.

(f) Exploration and production fluid transportation system permits are not transferable.

(g)(1) Exploration and production fluid transportation system permits shall be renewed annually on July 1 of each year, commencing on July 1, 2010.

(2) Amended applications, including any additional permit fees, are required to be submitted within thirty (30) days of the addition of any transportation tanks to the exploration and production fluid transportation system.

(h) Exploration and production fluid transportation system recordkeeping requirements:

(1) Each exploration and production fluid transportation system permit holder shall maintain a record of all exploration and production fluids received, transported, delivered or disposed of, which shall include the:

(A) Well lease or unit name;

(B) Well or facility operator (fluid generator);

(D) Amount per pick up;

(E) Type of fluid; and

(F) Name and location of the permitted off-site:

(i) Temporary storage facility;

(ii) Permitted surface disposal facility; or

(iii) Permitted injection well disposal facility; and

(2) Records shall be:

(A) Maintained a minimum of three (3) years at the Arkansas office of the exploration and production fluid transportation system permit holder; and

(B) Made available to Oil and Gas Commission staff for inspection during normal business hours.

(i) Exploration and production fluid transportation system operating requirements:

(1) All transportation tanks and associated piping and valves must be kept in leak-free condition;

(2)(A) Exploration and production fluid transporters shall only transport exploration and production fluid to a permitted:

(i) Well for reuse in the well drilling or well completion process;

(ii) Off-site temporary storage facility;

(iii) Surface disposal facility; or

(iv) Injection well disposal facility.

(B) Exploration and production fluid shall not be released or discharged onto the ground surface or into waters of the state unless otherwise authorized by the Division of Environmental Quality;

(3) All exploration and production fluids stored at a permitted temporary storage facility shall be contained in tanks or permitted temporary storage pits;

(4) Exploration and production fluid shall not be commingled or blended with nonexempt waste (such as used motor or compressor oil) under Subtitle C of the Federal Resource Conservation and Recovery Act of 1976; and

(5) All transportation tanks shall contain the name and phone number of the exploration and production fluid transporters in a legible manner.

(j) No person shall engage, employ, or contract with any other person except a permitted exploration and production fluid transporter to transport exploration and production fluids.

(k) Failure to comply with provisions of this section may result in revocation of the exploration and production fluid transportation system permit and/or the assessment of civil penalties in accordance with 15 CAR § 275-104.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: new rule January 22, 2009; amended October 24, 2009)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-504 Gathering and transportation of hazardous liquids by pipeline — Permitting and operational requirements {#sec-15-car-275-504 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-504}

15 CAR § 275-504. Gathering and transportation of hazardous liquids by pipeline — Permitting and operational requirements.

(a) Definitions. As used in this section:

(1) “Jurisdictional pipeline” means any onshore hazardous liquid pipeline regulated under federal regulation 49 C.F.R. pt. 195, as amended, which is within the jurisdiction of the Oil and Gas Commission (commission) in accordance with Arkansas Code § 15-71-110, as amended;

(2) “Nonjurisdictional pipeline” means any onshore hazardous liquid pipeline, including but not limited to flowlines, or gathering lines, not under jurisdiction of federal regulation 49 C.F.R. pt. 195, as amended, which is within the jurisdiction of the commission in accordance with Arkansas Code § 15-71-110, as amended;

(3) “Perennial stream” means:

(A) A stream that has flowing water year-round during a typical year;

(B) The water table is located above the stream bed for most of the year;

(D) Runoff from rainfall is a supplemental source of water for stream flow;

(4) “PHMSA” means the Pipeline and Hazardous Materials Safety Administration of the United States Department of Transportation;

(5) “Pipeline operator” means any person who owns or operates and is responsible for the construction, operation, and maintenance of a hazardous liquid pipeline which transports hazardous liquid from a point of beginning to severance the well within the jurisdiction of the commission in accordance with Arkansas Code § 15-71-110, as amended; and

(6) “Unusually sensitive area (USA)" means a drinking water or ecological resource area that is unusually sensitive to environmental damage from a hazardous liquid pipeline release, as identified under 49 C.F.R. § 195.6.

(b) Applicability.

(1) For purposes of this part, the jurisdiction of the commission, as specified in Arkansas Code § 15-71-110, as amended, extends to and includes:

(A) The gathering, storage, and transportation of crude oil, refined products, and CO₂: and

(B) Any other product in liquid form during transportation by pipeline subject to 49 U.S.C. § 60101, as defined in Arkansas Code § 15-71-110, as amended.

(2) Every pipeline operator transporting hazardous liquids by pipeline is subject to the applicable provisions of this part except for crude oil pipelines from a permitted oil well, to a lease stock tank located on the well pad, lease, or production unit which are exempt from the provisions of this part.

(1)(A) Each pipeline operator shall apply, on a form prescribed by the Director of Production and Conservation, for an initial statewide permit to construct, maintain, and operate a hazardous liquid pipeline system.

(B) The initial permit application shall contain at a minimum the following:

(i) Name, address, and contact information for the pipeline operator;

(ii) Map, in electronic form or other media acceptable to the director, showing the location of all hazardous liquid pipelines from the point of initial jurisdiction through any gathering or processing equipment or treating facility, pumping station, storage tank or tanks, and to the termination point of the jurisdiction of the commission, including all public road, railroads, and perennial stream and river crossings;

(iii) A determination as to what pipelines are jurisdictional.

(2) Each pipeline operator shall be required to submit an annual permit renewal by January 31 of each year.

(3)(A) The renewal permit shall include a revised pipeline map, if applicable, showing any new pipeline additions constructed or pipelines properly abandoned during the previous year, an annual report on a form prescribed by the director, and a permit renewal fee in accordance with subdivision (c)(1)(B)(iv) of this section.

(B) The renewal permit shall also contain the pipeline operator’s determination as to which pipelines are jurisdictional.

(4)(A) Each pipeline operator shall submit a Notice of Construction or Repair, on a form prescribed by the director, prior to commencing construction of a new pipeline or pipeline segment or within forty-eight hours (48) hours after completing repair to an existing pipeline, for each segment or project length of pipeline constructed during the year.

(B) The notice shall indicate the location and extent of the hazardous liquid pipelines to be constructed or repaired.

(5)(A) Each pipeline operator shall notify the director, or his or her designee, within five (5) calendar days of exceeding any hazardous liquid pipeline’s established maximum allowable operating pressure.

(B) This shall be submitted on a form prescribed by the director.

(6)(A) Each pipeline operator shall, at the earliest practicable moment, give notice to the commission of a release of any hazardous liquid, anhydrous ammonia, or carbon dioxide from any pipeline and submit a Notice of Incident, on a form prescribed by the director, for each incident of release due to pipeline failure which results in:

(i) A death or personal injury requiring inpatient hospitalization;

(ii) Either a fire or explosion not intentionally set by the operator;

(iii) Estimated property damage, including cost of cleanup and recovery, value of lost product, and damage to the property of the operator or others, or both, exceeding twenty-five thousand dollars ($25,000);

(iv) Pollution of any stream, river, lake, reservoir, or other similar body of water that violated applicable water quality standards, caused a discoloration of the surface of the water or adjoining shoreline, or deposited a sludge or emulsion beneath the surface of the water or upon adjoining shorelines;

(v) A release of five (5) or more barrels of crude oil or product from a pipeline; or

(vi) An event that is significant, in the judgment of the operator, even though it did not meet the criteria of subdivisions (c)(6)(A)(i), (ii), (iii), (iv), or (v) of this section.

(B) The notice required in subdivision (c)(6)(A) of this section shall be sent via phone or email to the commission regional office for the county where the event occurred, no later than two (2) hours after discovery and include the following information:

(i) Company/operator name;

(ii) Location of accident;

(iii) Time and date of accident;

(iv) Fatalities or personal injuries;

(v) Phone number of operator;

(vi) Telephone number of the operator's onsite person;

(vii) Other significant facts relevant to the accident, such as ignition, explosion, rerouting of traffic, evacuation of any building, and media interest.

(C) Following an incident reported as required by this section, the operator of the pipeline shall submit a Notice of Incident, on a form prescribed by the director for the incident due to hazardous liquid pipeline failure, within ten (10) business days.

(D)(i) Line markers must be located at each public road crossing, at each railroad crossing, and in sufficient number along the remainder of each buried line so that its location is accurately known.

(ii) The marker must state at least the following on a background of sharply contrasting color:

(a) The word “Warning,” “Caution,” or “Danger” followed by the words “Petroleum (or the name of the hazardous liquid transported) Pipeline”, “Anhydrous Ammonia” or “Carbon Dioxide Pipeline,” all of which, except for markers in heavily developed urban areas, must be in letters at least one inch (1") (25 millimeters) high with an approximate stroke of one-quarter inch (1⁄4") (6.4 millimeters).

(b) The name of the operator and a telephone number (including area code) where the operator can be reached at all times.

(7) Every pipeline operator shall be a member of a qualified One Call Center system.

(d) Requirements for all nonjurisdictional pipelines.

(1)(A) All pipelines crossing any stream or stream bed shall comply with applicable state rules and federal regulations.

(B) Additionally, any stream crossing of perennial streams, constructed on or after December 16, 2007, shall maintain a minimum of fifty feet (50') of undisturbed stream bank for the protection of the stream.

(C) However, the fifty feet (50') of undisturbed stream bank requirement may be modified by the director provided that the pipeline operator provides proof that the pipeline operator has received approval for the crossing from a state or federal agency.

(2)(A) Each pipeline operator shall place and maintain appropriate pipeline signage.

(B) Pipeline markers must be located at each public road crossing, at each railroad crossing, and in sufficient number along the remainder of each buried line so that its location is accurately known.

(i) The word “Warning,” “Caution,” or “Danger” followed by the words “Petroleum (or the name of the hazardous liquid transported) Pipeline”, “Anhydrous Ammonia” or “Carbon Dioxide Pipeline,” all of which, except for markers in heavily developed urban areas, must be in letters at least one inch (1") (25 millimeters) high with an approximate stroke of one-quarter inch (1⁄4") (6.4 millimeters);

(ii) The name of the operator and a telephone number (including area code) where the operator can be reached at all times.

(3) All pipelines constructed after the effective date of this part shall be buried at least twenty-four inches (24") below ground surface or in accordance with other applicable state or federal laws.

(e) Requirements for jurisdictional pipelines.

(1) All jurisdictional pipelines shall be in compliance with construction, operation, and maintenance and reporting requirements contained in federal regulation 49 C.F.R. pt. 195, as amended, which are herein incorporated by reference.

(2) All reports submitted to the Department of Transportation from jurisdictional pipeline operators shall be concurrently submitted to the commission.

(3) All pipeline operators of jurisdictional pipelines shall be subject to the applicable drug and alcohol testing requirements contained in federal regulation 49 C.F.R. pt. 199, as amended.

(4) Any pipeline operator determined to be in violation of 49 C.F.R. pt. 195 may be subject to civil penalties up to the amount set forth in 49 C.F.R. pt. 190 pursuant to the procedures set forth in 49 C.F.R. pt. 190 and 15 CAR § 275-104 as applicable.

(f) Additional requirements.

(1)(A) Additional requirements for pipeline operators of intrastate hazardous liquids pipelines, a hazardous liquids pipeline facility, an intrastate carbon dioxide pipeline, an anhydrous ammonia pipeline, or an anhydrous ammonia pipeline facility shall be included when any part of the pipelines or facilities are located within one thousand feet (1,000') of a public school building containing classrooms, or

(B) Within one thousand feet (1,000') of any other public school facility where students congregate or within one thousand feet (1,000') of any hospital, long-term care facility, public park, event center, or stadium, any pipeline or facility referenced in subdivision (f)(1)(A) of this section shall comply with the following:

(i) File with the commission in the initial pipeline permit application the following information:

(a) The name of the school, public school facility, hospital, long-term care facility, public park, event center, or stadium;

(b) The street address of the public school building, public school facility, hospital, long-term care facility, public park, event center, or stadium; and

(ii) File with the commission, on an annual basis, any updates to the above information on an ongoing basis for the duration of the pipeline or facility operation.

(2)(A) Any pipeline or facility referenced in subdivision (f)(1)(A) and (f)(1)(B) of this section shall have a written pipeline emergency response plan pertinent to the relevant school, school facility, hospital, long-term care facility, public park, event center, or stadium.

(B) The plan shall contain the following:

(i) A description and map of the pipeline facilities that are within one thousand feet (1,000') of the school building, school facility, hospital, long-term care facility, public park, event center, or stadium or facility;

(ii) A list of any product or products transported in the segment of the pipeline that is within one thousand feet (1,000') of the school facility;

(iii) The designated emergency number for the pipeline facility operator;

(iv) Information on the state's excavation one-call system;

(v) Information on how to recognize, report, and respond to a product release.

(3) The pipeline operator shall provide a copy of the pipeline emergency response plan to the commission and mail by certified mail, return receipt requested, to the superintendent of the school district, mayor’s office, event center, and stadium manager where the school, school facility, hospital, long-term care facility, public park, event center, or stadium is located.

(4)(A) The pipeline operator shall make every effort to meet with the appropriate official to explain the pipeline emergency response plan.

(B) All records documenting compliance with the requirements of this section, including documentation of any meetings or acknowledgment of receipt by the school district superintendent, or both, shall be retained for five (5) years from the date of the event that is commemorated by the record.

(C) Records of certified mail transmissions undertaken in compliance with this section satisfy the recordkeeping requirements of this subsection.

(g) Enforcement.

(1) Any regulated entity engaged in the operation of hazardous liquid pipelines are subject to the issuance of a notice of violation of any statutes or any rule or permit condition of the commission with respect to the hazardous liquid pipelines covered by this part.

(2) In accordance with Arkansas Code § 15-72-103(c), any person knowingly and willfully aiding or abetting any other person in the violation of any statute relating to the violation of any provision of the state statutes, or any rule, order, or permit condition dealing with hazardous liquid pipelines covered by this part, shall be subject to the same penalties as are prescribed herein for the regulated entity.

(3) All violations of this part shall be issued in accordance with 15 CAR § 275-104(a) – (f).

(4) Civil penalties.

(A) The director shall determine whether to request the assessment of civil penalties issued under this part with consideration given for compliance with applicable abatement requirements.

(B) If a civil penalty is requested by the director, the regulated entity may voluntarily agree to the assessment and pay the civil penalty as requested or modified by the director, or the director may file an application, in accordance with 15 CAR §§ 275-101 and 275-102, and other applicable hearing procedures, to request the issuance of the requested civil penalty by the commission.

(C)(i) The amount of the director’s requested civil penalty shall be based on the civil penalty amounts authorized by applicable federal law for violations of the United States Department of Transportation, Office of Pipeline Safety jurisdictional hazard liquid pipeline requirements.

(ii) However, the commission is not bound by the director’s request and may impose civil penalties of up to the maximum amounts permitted by law.

History

Codification Notes: "CO₂" means carbon dioxide. History: Ark. R. 2026-4 (eff. January 1, 2026) Authority: Arkansas Code § 15-71-110

Subpart 6

15 CAR § 275-601 Refinery reports {#sec-15-car-275-601 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-601}

15 CAR § 275-601. Refinery reports.

(a) Each refiner of oil within the State of Arkansas shall furnish for each calendar month a Refiner’s Monthly Report, containing the information and data indicated by such form, respecting oil and products involved in such refiner’s operations during each month.

(b) Such report for each month shall be prepared and filed according to instructions on the form, on or before the fifteenth day of the next succeeding month.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-602 Gasoline plant reports {#sec-15-car-275-602 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-602}

15 CAR § 275-602. Gasoline plant reports.

(a) Each operator of a gasoline plant, cycling plant, or any other plant at which gasoline, butane, propane condensate, kerosene, oil, or other liquid products are extracted from natural gas within the State of Arkansas, shall furnish for each calendar month a Monthly Gasoline or Other Extraction Plant Monthly Report, containing the information indicated by such form respecting natural gas and products involved in the operation of each plant during each month.

(b) Such reports for each month shall be prepared and filed according to instructions on the form on or before the fifteenth day of the next succeeding month.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: 1992 rule book)" Authority: Arkansas Code § 15-71-110

Subpart 7

15 CAR § 275-701 Abandoned or leaking well and well site remediation {#sec-15-car-275-701 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-701}

15 CAR § 275-701. Abandoned or leaking well and well site remediation.

(a) This section is applicable for the following types of wells:

(1) Oil and gas production wells;

(2) Water supply wells used in enhanced oil and gas recovery projects;

(3) UIC Class II disposal and Class II commercial disposal wells; and

(4) UIC Class II water injection wells used in enhanced oil and gas recovery projects.

(b) Definitions.

(1) “Abandoned well” means:

(A) An oil and gas production well which has not produced for over two (2) years;

(B) A UIC Class II saltwater disposal or UIC Class II water injection well which is no longer used due to the plugging of all the wells on the lease or unit or for which an agreement to continue use of the well has not been granted by the lease holder;

(C) A well for which the underlying lease has been released in writing by the lessee or has been declared forfeited or invalid by a court order, and such order is final and the appeal period has lapsed, and the lessor states in writing that the lessor has not leased out the oil and gas working interest to any other person and does not intend to so lease, and that the lessor does not intend to operate the well, and that the lessor desires that the well be plugged;

(D) A well owned or operated by a permit holder who has made no payment by March 1 of a current annual well fee assessment in accordance with Arkansas Code § 15-71-116;

(E) A well that has been ordered to be plugged by the Oil and Gas Commission and the permit holder has failed to do so within the time frame specified in the Oil and Gas Commission order; or

(F) A well site which has not been properly restored following the completion of well plugging activities;

(2) “Director” means the Oil and Gas Commission Director of Production and Conservation;

(3) “Leaking well” means a well drilled for the exploration, development, storage or production of oil or gas, or for injection, saltwater disposal, saltwater source, observation, and geological or structure test which is leaking saltwater, oil, gas, or other deleterious substance into any freshwater formation or onto the surface of the land in the vicinity of the well;

(4) “Well site” means the area around and near the well, including any associated pits, crude oil or produced water storage tanks, or other related production facility equipment, such as injection pumps, compressors, or gas processing equipment;

(5) “Well site equipment” means the equipment, including but not limited to an associated tank battery, production and injection facility equipment, hydrocarbons from the well that are stored in tanks located on the lease, and hydrocarbons recovered during the plugging operation; and

(6) “Well site restoration" means remediation of a well site, including but not limited to the following activities:

(A) An emergency cleanup of spilled crude oil or saltwater;

(B) Remediation of conditions endangering the public health or safety, or contaminating or potentially contaminating:

(i) Surface waters;

(ii) Groundwater; or

(iii) The surface of the land;

(C) Work to repair or contain leaks of produced fluids from wells, production or injection equipment, pits or other containment structures, which are contaminating or potentially contaminating:

(i) Surface waters;

(ii) Groundwater; or

(iii) The surface of the land; or

(D) Repairing a well leaking natural gas or hydrogen sulfide gas endangering or potentially endangering public safety or creating a potential fire hazard.

(c) If the Director of Production and Conservation finds, upon inspection and/or review of Oil and Gas Commission records, that a well drilled for the exploration, development, storage or production of oil or gas, or for injection, saltwater disposal, saltwater source, observation, and geological or structure test, may be abandoned, well site restoration has not been completed, is a leaking well, or the well or well site creates an imminent danger to the health or safety of the public, the director may schedule a hearing in accordance with established procedures.

(d) If after notice and a hearing, the commission finds that a well drilled for the exploration, development, storage, or production of oil or gas, or for injection, saltwater disposal, saltwater source, observation, a geological or structure test, may be abandoned, well site restoration has not completed, is a leaking well, or the well or well site creates an imminent danger to the health or safety of the public, the commission shall issue an order requiring the permit holder to properly plug, replug, repair, or restore so as to remedy the situation.

(e) If the permit holder fails to properly plug, replug, repair, or restore so as to remedy the situation within thirty (30) days from the time frame prescribed by the commission order, the abandoned well or well site, leaking well, a well or well site that creates an imminent danger to the health or safety of the public, or a well site restoration has not been completed, the well or well site shall be subject to the provisions of this section.

(f)(1) The director may then authorize any person to enter upon the land and properly plug, replug, repair, or restore so as to remedy the situation.

(2) The director may dispose of all well site equipment and hydrocarbons to offset the costs of properly plugging, replugging, repairing, or restoring so as to remedy the situation.

(3) Proceeds from any public sale, auction, or private sale of all well site equipment or hydrocarbons shall be deposited into the Abandoned and Orphaned Well Plugging Fund or used to offset plugging costs.

(4) All work completed under this section shall be paid with funds from the Abandoned and Orphan Well Plugging Fund.

(g)(1) The permit holder shall reimburse the commission for all costs expended to remedy the situation.

(2) All payments shall be:

(A) By cashier’s check or money order; and

(B) Deposited into the Abandoned and Orphaned Well Plugging Fund.

(3) Failure to reimburse the commission will result in the initiation of commission enforcement action to recover the expended funds.

(4) Prior to repayment of all expended funds, the permit holder shall not be permitted to operate any other existing wells in the permit holder’s name.

(5) Upon repayment and prior to being permitted to operate any wells, the permit holder may be required to post additional bond as determined by the director in accordance with 15 CAR § 275-202, to ensure against the plugging of future abandoned wells not plugged by the permit holder.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: new rule April 13, 2008; amended November 26, 2009)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-702 Plugging of orphan wells {#sec-15-car-275-702 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-702}

15 CAR § 275-702. Plugging of orphan wells.

(a) Definitions. As used in this section:

(1) “Director” means the Oil and Gas Commission Director of Production and Conservation;

(2) “Orphan well” means a well for which a permit holder can not be located, there is no record the well is covered by an Oil and Gas Commission required bond by the last known permit holder of record, and no fees have ever been paid on the well in accordance with Arkansas Code § 15-71-110;

(3) “Well site” means the area around and near the well, including any associated pits, crude oil, or produced water storage tanks or other related production facility equipment, such as injection pumps, compressors, or gas processing equipment; and

(4) “Well site equipment” means the equipment, including but not limited to an associated tank battery, production and injection facility equipment, hydrocarbons from the well that are stored in tanks located on the lease, and hydrocarbons recovered during the plugging operation.

(b)(1) If after review of the Oil and Gas Commission records, the Director of Production and Conservation determines a well or well site to be orphaned, that well or well site may be administratively determined to be eligible for plugging, without the need for a hearing.

(2) Following designation as an orphaned well or well site, the director may elect to properly plug, replug, or restore so as to remedy the situation, and authorize any person to enter upon the land to properly plug, replug, or restore so as to remedy the situation.

(c)(1) All work completed under this section shall be paid with funds from the Abandoned and Orphaned Well Plugging Fund.

(2) Additionally, the director may dispose of all well site equipment and hydrocarbons, to offset the cost of the well plugging and well site restoration operations.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: new rule April 13, 2008)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-703 Transfer of wells in the Abandoned and Orphaned Well Plugging Program {#sec-15-car-275-703 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-703}

15 CAR § 275-703. Transfer of wells in the Abandoned and Orphaned Well Plugging Program.

(a) Definitions. As used in this section:

(1) “Commission” means the Oil and Gas Commission;

(2) “Director” means the Director of Production and Conservation; and

(3) “Well” as used in this section shall only mean wells that are:

(A) Abandoned as defined in 15 CAR § 275-701(a)(1); or

(B) Orphaned as defined in 15 CAR § 275-702(a)(2).

(b) When a transfer request is received, on a form prescribed by the Director of Production and Conservation, for a well, the following documentation must be submitted by the proposed new permit holder:

(1) A signed new base lease properly recorded in the county where the well is located; or

(2) An affidavit stating a new base lease has been obtained and properly recorded in the county where the well is located.

(c) Upon review and acceptance of the transfer request, and prior to approval of the transfer request, the proposed new permit holder shall:

(1) Pay a salvage value for the downhole well equipment as follows:

(A) Five hundred dollars ($500) per well for wells less than three thousand feet (3,000’) in depth; and

(B) One thousand dollars ($1,000) per well for wells equal to or greater than three thousand feet (3,000’) in depth;

(2) Pay a salvage value for the tanks, pumping units, and other related equipment, as determined by submission of two (2) independent salvage value estimates from commercial salvage oil and gas production equipment dealers and approved by the director or his or her designee;

(3) Pay the fair market value per barrel, to be determined at the time of the transfer approval, for all oil fluids (hydrocarbons) stored on the lease or unit; and

(4) If applicable, provide financial assurance in accordance with 15 CAR § 275-202 and file all other required organizational and registration forms.

(d) All payments shall be by cashier’s check or money order, payable to the Oil and Gas Commission, and shall be deposited in the Abandoned and Orphaned Well Plugging Fund.

(e)(1) The director has sole discretion to approve or deny requests for transfer of the well.

(2) If, upon review of a transfer request for the well, the director determines that property rights, environmental or public safety and welfare concerns will be advanced through plugging the well, the transfer request may be denied.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: new rule April 13, 2008)" Authority: Arkansas Code § 15-71-110

Subpart 8

15 CAR § 275-801 Class II disposal, Class II commercial disposal, and Class V well permit application procedures {#sec-15-car-275-801 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-801}

15 CAR § 275-801. Class II disposal, Class II commercial disposal, and Class V well permit application procedures.

(a) Definitions.

(1) “Class II commercial disposal well" means a permitted Class II well in which Class II fluids are injected, for which the permit holder receives deliveries of Class II fluids by tank truck from multiple oil and gas well operators, and either charges a fee at the disposal well facility or purchases the Class II fluids at the source for subsequent transport to the disposal well facility for the specific purpose of disposal of the delivered Class II fluids;

(2) "Class II disposal well" means:

(A) A permitted Class II well in which Class II fluids are injected into zones not productive of oil and gas, and brine used to produce bromine, within the field boundary established by an order of the Oil and Gas Commission for the production of liquid hydrocarbons or brine used to produce bromine, where the well is located or will be located, for the purpose of disposal of those fluids; or

(B) A permitted Class II well in which Class II fluids are injected into a zone or zones which are not commercially productive of dry gas, within the same common source of supply, where the well is located or will be located, for the purpose of disposal of those fluids;

(3) “Class II enhanced oil recovery injection well (EOR well)” means a permitted Class II well into which Class II fluids are injected into zones productive of oil and gas contained within an enhanced oil recovery unit established by an order of the Oil and Gas Commission for the production of liquid hydrocarbons;

(4) "Class II fluids" means:

(A) Produced water and/or other fluids brought to the surface in connection with:

(i) Drilling, completion, or fracture treatments, workover or recompletion and plugging of oil and natural gas wells;

(ii) Class II wells that are required to be permitted as water supply wells by the Oil and Gas Commission;

(iii) Enhanced recovery operations; or

(iv) Natural gas storage operations;

(B) Produced water and/or other fluids from subdivision (a)(4)(A) of this section, above, which prior to reinjection have been used on site for purposes integrally associated to oil and natural gas well drilling, completion, or fracture treatments, workover or recompletion, and plugging of oil and natural gas wells, Class II or wells that are required to be permitted as water supply wells by the Oil and Gas Commission, enhanced recovery operations, or natural gas storage operations, or chemically treated or altered to the extent necessary to make them usable for purposes integrally related to oil and natural gas well drilling, completion, workover and plugging, oil and gas production, enhanced recovery operations, or natural gas storage operations, or commingled with fluid wastes resulting from fluid treatments outlined above, and including any other exempted oil and gas related fluids under the Resource Conservation and Recovery Act of 1976, 42 U.S.C. § 6901 et seq., provided the commingled fluid wastes do not constitute a hazardous waste under the Resource Conservation and Recovery Act of 1976, 42 U.S.C. § 6901 et seq.; or

(C) Waste fluids from gas plants (including filter backwash, precipitated sludge, iron sponge, hydrogen sulfide, and scrubber liquid) which are an integral part of oil and gas production operations, and waste fluids from gas dehydration plants (including glycol-based compounds and filter backwash), unless the gas plant or gas dehydration plant wastes are classified as hazardous under the federal Resource Conservation and Recovery Act of 1976, 42 U.S.C. § 6901 et seq.;

(5) “Class V brine injection well” means a permitted Class V well, located within an established unit (voluntary or Oil and Gas Commission established) created for the production of brine used to produce bromine and/or other chemical and mineral constituents of economic value, into which spent brine, following processing and removal of useable constituents, is injected into the zone of production;

(6)(A) “Confining layer” means a geological formation, group of formations, or part of a formation that is capable of limiting fluid movement above an injection zone.

(B) It is composed of rock layers that are impermeable or distinctly less permeable than the injection zone beneath it.

(7) “Disposal system” means a system for disposing of Class II fluids;

(8) “Permit holder” means the entity or person to whom the permit is issued and who is responsible for all regulatory requirements relative to the Class II disposal, Class II commercial disposal, Class II EOR, or Class V brine injection wells;

(9) “Spent brine fluid” means brine fluid and all constituents contained therein, including but not limited to any hydrocarbons, carbon dioxide, hydrogen sulfide, and other constituents contained in the brine, which prior to reinjection was produced for the purpose of processing the brine fluid to remove bromine, lithium, and other chemical and mineral constituents of economic value from the brine fluid;

(10) “UIC well” means any of the Class II disposal, Class II commercial disposal, Class II EOR, or Class V brine injection well types; and

(11) “USDW” means underground source of drinking water which is defined in 40 C.F.R § 144.3, as an aquifer or its portion which:

(i) Supplies any public water system (see 40 C.F.R.);

(ii) Contains a sufficient quantity of groundwater to supply a public water system (see 40 C.F.R.) and currently supplies drinking water for human consumption; or

(iii) Contains fewer than ten thousand micrograms per liter (10,000 mg/l) total dissolved solids (see 40 C.F.R.); and

(iv) Is not an exempted aquifer (see 40 C.F.R.).

(b)(1) No person shall drill, deepen, reenter, recomplete, or operate any UIC well or inject into any UIC well without the applicable permits, except as specified in subdivision (b)(3) of this section, below, from the Oil and Gas Commission, application for which shall be made on forms prescribed by the Director of Production and Conservation.

(2) Permits are valid only for the permit holder stated on the permit, and shall remain valid only with ongoing compliance with established operating requirements specified in 15 CAR § 275-802 or 15 CAR § 275-803, except that permits to drill, deepen, or reenter shall automatically expire six (6) months from the date of issuance, unless commencement of the drilling, deepening, or reentry of plugged well operations authorized by the permit has occurred, which are to be continued with due diligence, but not to exceed one (1) year from the date of commencement of the drilling, deepening, or reentry of plugged well operations authorized by the permit, at which time the well shall be plugged, injection casing set, or a new permit application, along with a new permit fee and plat, must be filed.

(3) Authority to conduct an injectivity test, step-rate test, or trial injection test prior to, or after the issuance of a permit, may be approved as follows:

(A)(i) An injectivity test, step-rate test, or trial injection test of less than twelve (12) hours duration may be approved by the Director of Production and Conservation upon review of the well construction to determine well mechanical integrity for the protection of the USDWs and oil and gas resources during the test.

(ii) The Director of Production and Conservation shall establish the protective parameters of the test, require the submittal of any information or test data deemed necessary, and may require the witnessing by Oil and Gas Commission staff of the test; and

(B) An applicant may request approval from the Oil and Gas Commission by filing an application in accordance with 15 CAR §§ 275-101 and 275-102, and other applicable hearing procedures, of an injectivity test, step-rate test, or trial injection test of twelve (12) hours or more in duration.

(4)(A) No UIC well may be drilled at a surface location other than that specified on the permit, except that if a permit holder has commenced drilling operations and the UIC well is lost due to adverse drilling conditions prior to surface casing being set, the permit holder may request an amendment of the permit without a fee for the new location, provided the UIC well remains on the same surface owners’ property where the UIC well was originally permitted and all other aspects of the permit request remain the same.

(B) Movement of the UIC well location off the original surface owners’ property, or after surface casing has been set, will require the filing of a new permit application, along with a new permit fee and plat.

(5) Permits to recomplete or operate shall automatically expire one (1) year from the date of issuance, unless commencement of the operations authorized by the permit has occurred, or a new permit application, along with a new permit fee has been filed.

(6) Upon issuance of a permit, a copy of the permit shall be displayed at the site where the UIC well is being drilled for review by Oil and Gas Commission staff.

(7) Permits to drill, deepen, or reenter a UIC well may only be issued if the location complies with 15 CAR § 275-203.

(c) Failure to comply with the operating requirements in 15 CAR § 275-802 or 15 CAR § 275-803, may result in revocation of the UIC well permit in accordance with subsection (s) of this section, below.

(d) All surface facilities, included but not limited to storage tanks, flowlines, injection equipment, related to UIC wells shall be regulated as follows:

(1) Any surface facility associated with a Class II disposal well shall be maintained and operated in accordance with 15 CAR § 275-219;

(2) Any surface facility associated with a Class II commercial disposal well shall be maintained and operated in accordance with 15 CAR § 275-219; and

(3) Any surface facility associated with a Class II EOR and Class V brine injection well shall be maintained and operated in accordance with 15 CAR § 275-219.

(e) The application to drill, deepen, reenter, recomplete, or operate a UIC well shall include at a minimum:

(1) The information required by subsection (h) of this section, below, for the existing or proposed UIC well and any additional information deemed necessary by the Director of Production and Conservation for the protection of USDWs;

(2) Accompanied by a drilling permit fee in the amount of three hundred dollars ($300) if the UIC well is drilled, deepened, or reentered;

(3) Accompanied by a nonrefundable application fee of:

(A) One hundred dollars ($100) for a Class II disposal, Class II EOR, or Class V brine injection well; or

(B) Five hundred dollars ($500) for a Class II commercial disposal well to recomplete or operate the UIC well;

(4) Accompanied by the required financial assurance in accordance with 15 CAR § 275-202;

(5) Accompanied by a Form 1 Organizational Report in accordance with 15 CAR § 275-212;

(6) Be executed under penalties of perjury;

(7) If the applicant is a corporation, limited liability company, limited liability partnership, or other business entity, it must be incorporated, organized, or authorized to do business in the State of Arkansas, and by filing an application, the applicant irrevocably waives, to the fullest extent permitted by law, any objection to a hearing before the Oil and Gas Commission or in a court of competent jurisdiction in Arkansas;

(8) If the applicant is an individual, partnership, or other entity that is not a resident of Arkansas, the applicant must be authorized to do business in Arkansas, and by filing an application, the applicant irrevocably waives, to the fullest extent permitted by law, any objection to a hearing before the Oil and Gas Commission or in a court of competent jurisdiction in Arkansas;

(9) Proof that the UIC well location complies with 15 CAR § 275-203; and

(10) If the application is for a Class II disposal well:

(A) A plat showing the location and proposed or existing configuration of the storage tank disposal facility;

(B) The total disposal storage capacity of Class II fluids at the facility; and

(f) No person shall inject into USDWs or be issued a permit to inject into USDWs unless an aquifer exemption has been granted in accordance with United States Environmental Protection Agency procedures.

(g)(1) Unless otherwise approved by the Oil and Gas Commission, no person shall inject into a UIC well which does not have, at a minimum, five hundred feet (500’) for a Class II disposal well or seven hundred fifty feet (750’) for a Class II commercial disposal or Class V brine injection well, of confining layers between the base of the lowermost USDWs and the top of the injection interval, with no individual confining layer being less than fifty feet (50’) in thickness.

(2) A lesser amount of confining layers may be approved, provided the applicant provides substantial information as to the integrity of the confining layers to inhibit the upward migration of the injection fluids so as not to endanger the lowermost USDW in the area of the UIC well.

(h)(1) If the application does not contain all of the required information or documents, the Director of Production and Conservation shall notify the applicant in writing.

(2) The notification shall:

(A) Specify the additional information or documents necessary for an evaluation of the application; and

(B) Advise the applicant that the application will be deemed denied unless the information or documents are submitted within sixty (60) days following the date of notification.

(i) Applications for a Class II disposal well shall contain the names of all permit holders who are to utilize the proposed disposal well.

(j) Contents of application.

(1) A specification as to the type of UIC well being permitted.

(2) The applicant shall provide the name, address, phone, fax, and email (if available) of the local or on-site supervisory or field personnel responsible for the disposal well.

(3)(A) If the Class II disposal well is not located within the boundaries of an operating oil and gas leasehold or drilling unit, the applicant shall provide documentation, in the form of a surface use agreement or an affidavit of a surface use agreement, indicating the applicant’s right to drill and to operate the proposed Class II disposal well.

(B) If the Class II disposal well is located within the boundaries of an operating oil and gas leasehold or drilling unit, and the applicant is someone other than the operator of the leasehold or drilling unit, the applicant shall provide documentation, in the form of a surface use agreement, or an affidavit of a surface use agreement, indicating the applicant’s right to drill and to operate the proposed Class II disposal well.

(C) If the well is a Class II commercial disposal well, the applicant shall provide documentation, in the form of a surface use agreement, or an affidavit of a surface use agreement, indicating the applicant’s right to drill and to operate the proposed Class II commercial disposal well.

(4)(A) A survey plat of the location and ground elevation of the proposed UIC well, or if the application is for a previously permitted well, the well name and permit number of the previously permitted well.

(B) A new survey is not required for a well to be converted or deepened, or a plugged well to be reentered, if the original well location was surveyed, a copy of which shall be submitted with the application.

(5)(A) The name, geologic description, and the approximate top and bottom elevation, from subsea, of the formation (indicating the perforated or open hole interval) into which fluid will be injected and the geologic description and top and bottom elevation, from subsea, of the above confining layers, in the proposed or previously permitted UIC well.

(B)(i) If a previously permitted well is to be converted, a geophysical log of the previously permitted well shall be submitted showing the above information.

(ii) For a proposed well, an induction log from a well in the immediate vicinity of the proposed UIC well shall be submitted.

(C) If the geologic name of the interval is unclear, include any additional geological evidence such as a cross-section, structure, or isopach map that may be necessary to adequately define the proposed injection interval.

(6)(A) A well bore diagram of the proposed or previously permitted well showing from the wellhead to total depth of the well:

(i) All casings and cementing of casings;

(ii) Any obstructions within well;

(iii) All plugs set, tubing and packer setting depth; and

(iv) All perforations and/or open hole intervals.

(B) If application is for a previously permitted well, a cement bond log (CBL) shall be submitted with the application, or if submitted after the application is filed, the CBL shall be submitted prior to commencement of operations as a condition of the permit.

(7)(A) The proposed daily amounts to be injected, the source and the type of fluid to be injected, and standard laboratory report from an accredited laboratory reporting the laboratory results of a representative sample of the proposed fluids to be injected, for the following parameters:

(i) Chloride;

(ii) pH;

(iii) Specific gravity;

(iv) Total dissolved solids (TDS); and

(v) Total percent hydrocarbon (TPH).

(B) The sample shall be obtained and analyzed no earlier than one hundred eighty (180) days prior to the date of filing of the application and analyzed in a timely fashion after collection.

(8) The maximum injection pressure.

(A) The Director of Oil Conservation and Production shall determine the maximum permitted injected pressure, measured at the wellhead, by multiplying the results of the formula below by ninety percent (90%):

(i) A maximum fracture gradient not to exceed 1.1 psi/ft (x) depth to injection formation (-) weight of fluid column (specific gravity of injection fluid) (+) injection tubing friction loss in Ashley, Bradley, Calhoun, Columbia, Hempstead, Lafayette, Miller, Nevada, Ouachita, and Union counties for injection into formations below the Midway Shale Formation;

(ii) A maximum fracture gradient not to exceed 1.0 psi/ft (x) depth to injection formation (-) weight of fluid column (specific gravity of injection fluid) (+) injection tubing friction loss in all other counties for injection into formations below the Fayetteville Shale Formation in the areas covered by 15 CAR §§ 275-230(c) and (d), 15 CAR § 275-231, and the portions of Franklin, Logan, Scott, Sebastian, and Yell counties not covered by 15 CAR § 275-231; or

(iii) A maximum fracture gradient not to exceed 0.73 psi/ft (x) depth to injection formation (-) weight of fluid column (specific gravity of injection fluid) (+) injection tubing friction loss for all other formations and/or counties.

The following calculation is included only as an example, and for informational and demonstrative purposes only.

For purposes of this example, assume the well is in Columbia County, the total depth to the injection formation is two thousand five hundred feet (2,500’), the specific gravity is one and eighty-five thousandths (1.085), and the injection tubing friction loss is two hundred fifty pounds per square inch (250 psi).

Using the formula provided above, the maximum permitted injection pressure for the well would be one thousand six hundred forty-two pounds per square inch gauge (1,642 psig), calculated as follows:

Step 1: 0.9 x [(1.1 psi/ft x 2,500 ft) – [0.433psi/ft x 2,500 ft) x 1.085 (specific gravity)] + 250 tubing friction loss] Step 2: 0.9 x [2,750 psi – 1,175 + 250 tubing friction loss] Step 3: 0.9 x [1,825] Step 4: Result = 1,642 psig

(B)(i) An applicant may request an increase in the maximum injection pressure specified in subdivision (j)(8)(A) of this section, above, or appeal a Director of Production and Conservation’s decision to issue a permit utilizing a fracture gradient less than the maximum fracture gradient specified in subdivision (j)(8)(A) of this section, above, by filing an application in accordance with 15 CAR §§ 275-101 and 275-102 and other applicable hearing procedures.

(ii) Any increase in the maximum injection pressure may be granted if the applicant presents sufficient evidence to justify the requested increased injection pressure will not initiate or propagate fractures in the overlying confining layer or layers that could enable the injection fluid or the fluid in the injection interval to leave the permitted injection intervals or cause movement of the injection fluid or formation fluids into USDWs.

(9) A map showing:

(A) The surveyed location of the UIC well proposed to be drilled, deepened, or converted, showing distances to the nearest property or lease lines; and

(B) The location of all known plugged and unplugged wells, which penetrate the proposed injection interval, within the one-half (1/2) mile radius from the proposed disposal well, and showing the status of each well as:

(i) Producing;

(ii) Shut-in;

(iii) Disposal;

(iv) Enhanced recovery;

(v) Plugged and abandoned; or

(vi) Other status.

(10)(A) The applicant shall submit evidence, where available, that all plugged and unplugged wells which penetrate the injection formation, within the one-half (1/2) mile radius shown on the above plat in subdivision (j)(9)(B) of this section, contain an adequate amount of cement and are constructed or plugged in a manner which will prevent the injection fluid and the fluid in the injection formation from entering USDWs.

(B) The types of evidence that will be considered acceptable include, but are not limited to:

(i) Well completion reports;

(ii) Cementing records;

(iii) Well construction records;

(iv) Cement bond logs;

(v) Tracer surveys;

(vi) Oxygen activation logs; and

(vii) Plugging records.

(11) The applicant shall submit evidence and/or information showing that the proposed injection interval or formation is not a USDW.

(12) The applicant shall submit information as to the depth (subsea) of the freshwater supply in the nearest known private water well and in the nearest known public water system water well.

(13) If the application is for a Class II commercial disposal well, a listing of all previous and current violations of any statute, rule, permit condition, or order of the Oil and Gas Commission, the Division of Environmental Quality, the Arkansas Pollution Control and Ecology Commission, or any other state or federal environmental regulatory agency, including those of other states, regarding oil or gas related activities.

(k)(1) Notice of the application shall be given by the applicant by:

(A) One (1) publication in a legal newspaper having a general circulation in the county, or in each county, if there shall be more than one (1), in which the one-half (1/2) mile radius from the proposed disposal well is situated; and

(B) Mailing via certified mail, FedEx, UPS, or other method that provides proof of mailing and delivery, a copy of the application to each permit holder of all permitted, drilling, or producing wells within a one-half (1/2) mile radius of the proposed disposal well.

(2) Such notice shall be published or mailed no more than thirty (30) days prior to the date on which the application is filed with the Oil and Gas Commission.

(3) The cost of such notice and mailing of the application shall be paid for by the applicant.

(4) Attached to the application shall be evidence that the application was mailed or sent as required and a proof of publication of the application from the newspaper.

(l)(1) If notice is for a Class II commercial disposal well, in addition to compliance with subsection (i) of this section, above, the Class II commercial disposal well application shall also be sent via certified mail, FedEx, or UPS to the county judge of the county where the well is located and to the landowner (surface owner) where the well is located.

(2) In addition, the public notice should be large font and surrounded by a printed border to highlight the published notice.

(m) Objections received by the Director of Production and Conservation, must be received by the Director of Production and Conservation within fifteen (15) days after the publication date of the notice and the date of mailing or sending to all parties specified in subsections (k) and (l) of this section, above.

(n)(1) If an objection is received, the application shall be deemed denied.

(2) If the application is denied under this section, the applicant may request to have the application referred to the Oil and Gas Commission for determination, in accordance with 15 CAR §§ 275-101 and 275-102, and other applicable hearing procedures, except that no additional filing fee is required.

(o) If an objection is not received by the Director of Production and Conservation and the application is deemed complete, the permit shall be issued following the required notice period specified in subsection (k) of this section, above, unless the Director of Production and Conservation deems it necessary, for the purpose of protecting USDWs or oil and gas resources, that the application may be referred to the Oil and Gas Commission for determination, and no additional filing fee is required from the applicant.

(p)(1) If the application does not satisfy the requirements of this section, the application shall be denied.

(q) If the applicant satisfies the requirements of all applicable statutes and this section, a permit shall be issued, unless:

(1) The applicant has falsified or otherwise misstated any material information on or relative to the permit application; or

(2) For purposes of Class II commercial disposal wells, the applicant:

(A) Has an owner, officer, director, partner, or member or manager of a limited liability company, or other person with an interest in the entity exceeding five percent (5%):

(i) That has failed to abate an outstanding violation of the oil and gas statutes or rules, or comply with an order of the Oil and Gas Commission as specified in a final administrative decision of the Oil and Gas Commission;

(ii) For which funds have been obligated and remain outstanding from the Abandoned and Orphaned Well Plugging Fund to plug wells, under 15 CAR § 275-701 or 15 CAR § 275-702; or

(iii) Who is delinquent in payment of any annual well fees under 15 CAR § 275-202;

(B) Was an owner, officer, director, partner, or member or manager of a limited liability company, or other person with an interest exceeding five percent (5%):

(ii) For which funds have been obligated and remain outstanding from the Abandoned and Orphaned Well Plugging Fund to plug wells, under 15 CAR § 275-701 or 15 CAR § 275-702; or

(iii) Who is delinquent in payment of any annual well fees under 15 CAR § 275-202;

(C) Is a permit holder or an owner, officer, director, partner, or member or manager of a limited liability company, or other person with an interest exceeding five percent (5%):

(ii) For which funds have been obligated and remain outstanding from the Abandoned and Orphaned Well Plugging Fund to plug wells, under 15 CAR § 275-701 or 275-702; or

(iii) Who is delinquent in payment of any annual well fees under 15 CAR § 275-202;

(D)(i) If the Director of Production and Conservation determines that the applicant, or an owner, officer, director, partner, or member or manager of a limited liability company, or other person with an interest exceeding five percent (5%) in the applicant, has a history of violating an oil and gas statute, rule, permit condition, or order of the Oil and Gas Commission, the Division of Environmental Quality, the Arkansas Pollution Control and Ecology Commission, or any other state or federal environmental regulatory agency, including those of other states, regarding oil or gas related activities, which pose a potential danger to the environment and public health and safety.

(ii) In making the determination, the Director of Production and Conservation may consider:

(a) The danger to the environment and public health and safety if the applicant's proposed activity is not conducted in a competent and responsible manner; and

(b) The degree to which past and present oil and gas related activities directly bear upon the reliability, competence, and responsibility of the applicant; and

(E) If a permit is not issued in accordance with subsection (o) of this section, above, the applicant may request to have the permit application referred to the Oil and Gas Commission for determination, in accordance with 15 CAR §§ 275-101 and 275-102, and other applicable hearing procedures, except that no additional filing fee is required.

(r) The Oil and Gas Commission retains jurisdiction to determine zones suitable for injection based on the porosity, permeability, fluid capacity, structure, geology, and overall suitability of the zone as a disposal injection interval with respect to protection of USDWs, oil and gas resources, and correlative rights.

(s) UIC well drilling permit or transfer revocation procedures.

(1) The Director of Production and Conservation may revoke a UIC well permit or transfer approval if the:

(A) Permit holder fails to meet permit conditions as specified in the UIC well permit or transfer approval;

(B) UIC well permit or transfer approval was issued in error; or

(2)(A) The Director of Production and Conservation shall notify the permit holder of the UIC well permit or transfer revocation in writing.

(B) Following the revocation notice, the permit holder is required to plug the UIC well.

(C) The permit holder shall have thirty (30) days from the date of the UIC well permit or transfer revocation to appeal the Director of Production and Conservation’s decision to revoke the UIC well permit or transfer approval in accordance with 15 CAR §§ 275-101 and 275-102 and other applicable hearing procedures.

(D) Operations may not commence or continue during the appeal process.

(E) A revocation of a UIC well permit or transfer approval for which an appeal has not been filed shall become a final administrative decision of the Oil and Gas Commission thirty (30) days following the date of the revocation.

(t) UIC well transfer procedures.

(1) Definitions.

(A) "Current permit holder" means the individual or entity required to hold the permit or to whom the permit was issued and who:

(i) Is the owner of the right to operate said UIC well;

(ii) Possesses the full rights and responsibilities for operating the UIC well in accordance with applicable Arkansas law;

(iii) Has the current obligation to plug said UIC well; and

(iv) Is the assignor, transferor, or seller, whether voluntary or involuntary, of the UIC well;

(B) "New permit holder" means the individual or entity acquiring the UIC well and the right to operate said UIC well, who:

(i) Obtains the full rights and responsibilities for operating the UIC well in accordance with applicable Arkansas law and/or rule or order of the Oil and Gas Commission;

(ii) Will obtain the obligation to plug said UIC well; and

(iii) As owner or operator in accordance with applicable Arkansas law and/or rule or order of the Oil and Gas Commission is required to hold the permit; and

(C) “Transfer” means any assignment, devise, release, transfer, takeover, buyout, merger, sale, conveyance, or other transfer of any kind, whether voluntarily or involuntarily.

(2) The provisions of this subsection apply to all transfers of the interest of the individual or entity required to hold and to whom the UIC well transfer approval is issued (permit holder), including but not limited to, a change:

(A) Of ownership of the right to drill and/or operate said UIC well, along with the full rights and responsibilities for operating the UIC well, and the obligation to ultimately plug said UIC well;

(B) In the designation of the owner or operator under an operating or other similar agreement;

(D) Required by the appointment, by a court of competent jurisdiction, of a trustee or a receiver to exercise custody and control over the UIC well, including the right to drill and/or operate said well along with the full rights and responsibilities for operating the UIC well.

(3) The provisions of this subsection shall not apply to the transfer of working interests not affecting the rights or responsibilities of the permit holder.

(4)(A) The provisions of this subsection shall not apply to transfers of UIC wells abandoned or orphaned in accordance with15 CAR § 275-701 or 15 CAR § 275-702.

(B) Transfers of UIC wells deemed abandoned or orphaned are subject to the transfer provisions in 15 CAR § 275-703.

(5) Notification of a transfer shall be given to the Director of Production and Conservation, or his or her designee by the current permit holder, on a form prescribed by the Director of Production and Conservation, of the transfer of any UIC well or any UIC well required to be permitted within thirty (30) days after the effective date of the transfer.

(6) A separate form shall be completed for each lease, UIC well, or other unit transferred.

(7) The notification shall be signed by the current permit holder and the new permit holder, or by authorized representatives specified on the organizational report filed in accordance with 15 CAR § 275-212, except as follows:

(A) In lieu of the signature of the current permit holder, the new permit holder may submit a court order or other legal document evidencing ownership of the lease or unit to be transferred in the event that the current permit holder cannot be located or refuses to sign the notification of transfer form; or

(B) In lieu of the signature of the new permit holder, the current permit holder may submit documentation evidencing transfer of the ownership of the UIC well, lease, or unit in the event the new permit holder refuses to sign the notification of transfer form.

(8)(A) A new permit holder may operate UIC wells covered by the UIC well transfer request until such time as the transfer request has been approved or denied by the Director of Production and Conservation or his or her designee, provided the request was submitted within thirty (30) days of the actual transfer of the UIC well.

(B) However, the UIC wells may not be operated by the new permit holder until a UIC well transfer request is approved, if the request was received by the Director of Production and Conservation, or his or her designee, more than thirty (30) days after the actual transfer of the UIC well.

(9) A new permit holder that acquires the right to operate a UIC well pursuant to a transfer shall apply for and must receive transfer approval from the Director of Production and Conservation, or his or her designee prior to operating the UIC well beyond the timeframe specified in subdivision (t)(8) of this section, above.

(10) Prior to the Director of Production and Conservation, or his or her designee approving the transfer request, the new permit holder shall provide the required financial assurance, if applicable, in accordance with 15 CAR § 275-202, and file the required organizational report, if applicable, in accordance with 15 CAR § 275-212.

(11) A transfer to a new permit holder may be denied by the Director of Production and Conservation, or his or her designee if the new permit holder meets any of the conditions specified in subsection (q) of this section, above.

(12)(A) The new permit holder shall be responsible for all regulatory requirements relative to all UIC wells and all other surface production facilities in existence at the time of the transfer related to the UIC wells.

(B) The new permit holder shall not be responsible for regulatory requirements relative to spills of crude oil or other production fluids which occurred prior to the date of the transfer, unless the new permit holder has otherwise agreed with the current permit holder.

(13)(A) If any UIC well, or any lease or other unit associated with the UIC well, is in violation at the time of the transfer request to the new permit holder, the transfer request shall be denied pending abatement of all violations by the current permit holder.

(B) However, if the new permit holder, after being notified of the violations, agrees in writing to the transfer approval including conditions to abate all violations, the transfer may be approved by the Director of Production and Conservation, or his or her designee.

(C) Failure to abate the violations within the time period specified by the Director of Production and Conservation or his or her designee may result in revocation of the transfer approval in accordance with subsection (s) of this section, above, and/or other applicable enforcement actions in accordance with 15 CAR § 275-104.

(14)(A) The current permit holder is not responsible for any regulatory violation caused by the actions of the new permit holder during the permit transfer process, after notice is given to the Director of Production and Conservation, or his or her designee by the current permit holder of the pending transfer if the transfer is approved.

(B) However, if the transfer is denied by the Director of Production and Conservation or his or her designee, the current permit holder assumes all responsibility for the violations caused by the new permit holder.

(C) Nothing in this subsection shall affect the contractual rights and obligations between the person or entity transferring the UIC well and the person or entity acquiring the UIC well.

(15)(A) The transfer approval pursuant to this subsection shall not affect the rights of the Oil and Gas Commission, or any obligation or duty of the current permit holder arising under any applicable Arkansas laws, or rules or orders of the Oil and Gas Commission.

(B) Any cause of action accruing or any action or proceeding which has commenced, whether administrative, civil, or criminal, may be instituted or continued without regard to the transfer approval.

(16)(A) The Director of Production and Conservation shall notify the current and new permit holder of the transfer approval or denial in writing.

(B) Following the approval or denial of the transfer approval request, the current or new permit holder shall have thirty (30) days from the date of the approval or denial to appeal the Director of Production and Conservation’s decision in accordance with 15 CAR §§ 275-101 and 275-102 and other applicable hearing procedures.

(C) A transfer request approval or denial, for which an appeal has not been filed, shall become a final administrative decision of the Oil and Gas Commission thirty (30) days following the date of the approval or denial.

(u) Miscellaneous provisions and requirements for Class II disposal or Class II commercial disposal wells within 15 CAR § 275-230(c) lands.

(1) Definitions.

(A) “Moratorium zone deep faults” means deeper faults associated with the Guy-Greenbrier Earthquake Swarm, and which are part of a general northeast-southwest (approximately N30ºE) trending deeper fault system displacing the Lower Ordovician through Precambrian strata occurring in 15 CAR § 275-230, subsection (c) lands area; and

(B) “Regional fault” means the identified fault zones named by the Arkansas Geological Survey as the Clinton, Center Ridge, Heber Springs, Enders, and Morrilton Fault zones, and which are part of a general east-west turning north-east (approximately N55ºE to N75ºE) trending, down thrown to the south, fault system generally occurring below the Fayetteville Shale Formation displacing the Lower Mississippian through Precambrian strata, and truncating upward at the unconformity between the Mississippian and Pennsylvanian age strata, and which are identified on the Arkansas Geological Survey map attached hereto as Exhibit 1 to this section, and as updated for purposes of this section following notice and a hearing in accordance with 15 CAR § 275-101.

(2) Unless otherwise approved by the Oil and Gas Commission after notice and a hearing, no permit to drill, deepen, reenter, recomplete, or operate a Class II disposal or Class II commercial disposal well may be granted for any Class II or Class II commercial disposal wells in any formation within the following area (moratorium zone) located in Cleburne, Conway, Faulkner, Van Buren, and White counties:

| Sections | Township | Range | | --- | --- | --- | | ALL | 4N | 13W | | ALL | 5N | 12W | | ALL | 5N | 13W | | ALL | 5N | 14W | | ALL | 6N | 12W | | ALL | 6N | 13W | | ALL | 7N | 11W | | ALL | 7N | 12W | | ALL | 7N | 13W | | ALL | 8N | 11W | | ALL | 8N | 12W | | ALL | 8N | 13W | | ALL | 9N | 10W | | ALL | 9N | 11W | | ALL | 9N | 12W | | ALL | 10N | 10W | | ALL | 10N | 11W | | ALL | 11N | 10W | | ALL | 11N | 11W | | 1-12, 14-23, 27-33 1-30, 35-36 1-2, 10-15, 23-25 4-9, 17-20, 30-31 25, 35-36 6 | 4N 4N 4N 5N 5N 6N | 12W 14W 15W 11W 15W 10W | | 1-23, 26-34 1-4, 9-36 24-25, 36 3-9, 16-20, 29-31 1, 11-14, 22-27, 34-36 6-7 | 6N 6N 6N 7N 7N 8N | 11W 14W 15W 10W 14W 9W | | 1-24, 26-35 25, 36 3-10, 15-21, 29-32 1-5, 7-36 1-23, 27-34 1-3, 9-17, 19-36 25, 33, 34, 36 17-22, 27-35 13, 23-27, 34-36 | 8N 8N 9N 9N 10N 10N 10N 11N 11N | 10W 14W 9W 13W 9W 12W 13W 9W 12W |

(3) Unless otherwise approved by the Oil and Gas Commission after notice and a hearing, no permit to drill or reenter a new Class II disposal or Class II commercial disposal well may be granted within one (1) mile of a regional fault or within five (5) miles of a known or identified moratorium zone deep fault within any remaining 15 CAR § 275-230 subsection (c) lands.

(4) Unless otherwise approved by the Oil and Gas Commission after notice and a hearing, no permit to deepen or recomplete any existing Class II disposal or Class II commercial disposal well in a zone stratigraphically below the Fayetteville Shale Formation, may be granted within one (1) mile of a regional fault or within five (5) miles of a known or identified moratorium zone deep fault within any remaining 15 CAR § 275-230 subsection (c) lands.

(5) Unless otherwise approved by the Oil and Gas Commission after notice and a hearing, the following provisions shall apply to any permit to drill, deepen, or operate a new Class II disposal or Class II commercial disposal well proposed to be located within any remaining 15 CAR § 275-230 subsection (c) lands:

(A) No Class II disposal or Class II commercial disposal well disposing in a zone occurring stratigraphically below the Fayetteville Shale Formation shall be located within five (5) miles of another Class II disposal or Class II commercial disposal well disposing in a zone occurring stratigraphically below the Fayetteville Shale Formation; and

(B) No Class II disposal or Class II commercial disposal well disposing in a zone occurring stratigraphically above the Fayetteville Shale Formation shall be located within one-half (1/2) mile of another Class II disposal or Class II commercial disposal well disposing in a zone occurring stratigraphically above the Fayetteville Shale Formation.

(6)(A) The applicant shall provide technical information to the Director of Production and Conservation in support of the application.

(B) The technical justification shall include information related to the location of any moratorium zone deep fault within five (5) miles or regional fault within two (2) miles of the proposed location of the Class II disposal or Class II commercial disposal well, with special emphasis on identifying any deep faults occurring below the Fayetteville Shale Formation which extend to the basement rock.

(7) Flow meters, or other measuring devices approved by the Director of Production and Conservation, shall be installed on all Class II disposal and Class II commercial disposal wells and permit holders shall submit accurate injection volume and pressure information, on no less than a daily basis, on a form prescribed by the Director of Production and Conservation.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: new rule July 17, 2009; amended November 26, 2009; amended July 30, 2010; amended July 29, 2011; amended February 17, 2012; amended June 16, 2019; amended November 28, 2024)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-802 Well construction, operating, and reporting requirements for Class II disposal wells {#sec-15-car-275-802 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-802}

15 CAR § 275-802. Well construction, operating, and reporting requirements for Class II disposal wells.

(a) No Class II disposal or EOR well, as defined in 15 CAR § 275-801(a)(2), hereinafter referred to as “Class II well” for purposes of this section, for which a permit has been issued in accordance with 15 CAR § 275-801, shall be operated until:

(1) Well internal mechanical integrity has been established in accordance with subsection (o) of this section, below; and

(2) An authority for initial commencement of injection operations is issued by the Director of Production and Conservation.

(b)(1) The permit holder shall provide notice to the Oil and Gas Commission regional office where the Class II well is located, prior to performing any well servicing activity, cementing, or any wireline logging activities, so as to allow commission staff to be present to observe the activity.

(2) Any well servicing which requires the resetting of the packer shall require an internal mechanical integrity test be run in accordance with subsection (o) of this section, below, prior to recommencement of injection.

(c)(1) All well records for newly drilled Class II wells shall be submitted in accordance with 15 CAR § 275-205.

(2) Completion or recompletion reports and wireline logs for all subsequent well servicing, cementing, or wireline logging activity performed on the well shall be filed no later than fifteen (15) days after completion of these activities.

(d) Following issuance of the permit to drill and/or operate a Class II well, an annual fee of one hundred dollars ($100) per well shall be due each July 1 for the life of the well until the well is plugged.

(e) Surface and production casing requirements.

(1) Class II wells shall be cased and cemented in such manner that damage will not be caused to any USDW, as defined in 15 CAR § 275-801(a)(5), hereinafter referred to as “USDW”, or oil and gas resources.

(2) For newly drilled Class II wells:

(A) Set and cement surface casing two hundred fifty feet (250’) below the base of the lowermost USDW, and cement production casing to at least two hundred fifty feet (250’) above the proposed disposal zone; or

(B) Set and cement surface casing fifty feet (50’) below the base of the lowermost formation utilized for a public water system (see 40 C.F.R.) in the area of the Class II well, with a minimum of five hundred feet (500’) of surface casing required, and cement production casing back to the surface.

(3) For existing wells converted to Class II wells:

(A)(i) Unless otherwise approved by the director, production casing in the existing well is required to be cemented to at least two hundred fifty feet (250’) above the proposed disposal zone.

(ii) A cement bond (CBL), gamma ray (GR), and density log (VDL) shall be required to verify the presence of the required casing cement.

(iii) The CBL should indicate at a minimum an eighty percent (80%) bond index over the two-hundred-fifty-foot cemented interval; and

(B) If a casing liner is required to provide well bore integrity above the required production cementing requirements in subdivision (e)(3)(A) of this section, above, the liner must be set, at a minimum, below the cemented portion of the production casing and cemented back to the surface.

(f) Tubing and packer requirements.

(1)(A) All injections shall be through tubing and packer.

(B) The packer shall be placed no higher than one hundred feet (100’) above the uppermost perforations or the casing seat in an open hole completion, provided the packer is within the cemented portion of the production casing, provided the packer is no less than five hundred feet (500’) below the base of the USDW.

(2)(A) If the tubing and packer cannot be set or utilized in accordance with subdivision (f)(1) of this section, above, due to existing well construction conditions, the permit holder may request the director to authorize an alternative packer setting depth or well construction.

(B) In determining an alternative packer setting depth or alternative well construction, the director shall take into consideration the:

(i) Current construction of the well;

(ii) Depth of the USDWs; and

(iii) Nature of the obstruction.

(i) Additional or more frequent internal mechanical integrity tests be performed on the well; or

(ii) Additional remedial or corrective work to assure that injection does not endanger USDWs.

(3) The permit holder shall contact the regional office in which the well is located at least twenty-four (24) hours prior to the initial setting or any resetting of the packer in a Class II disposal well to enable an inspector to be present when the packer is set.

(g)(1) The wellhead shall be maintained in a leak-free condition, and must have a working pressure gauge in excess of the maximum discharge pressure of the pump.

(2) The wellhead shall be configured to include a one-half-inch female fitting, with shut-off valve, to allow monitoring of the annulus between the production casing and the injection tubing and a one-half-inch female fitting, with shut-off valve, installed on the tubing to measure the injection pressure.

(h) The injection pressure shall not exceed the maximum injection pressure established in accordance with 15 CAR § 275-801(j)(8).

(i) No change shall be made in the permitted injection zone unless the new zone is permitted in accordance with 15 CAR § 275-801.

(j)(1) Injection fluids shall be confined to the permitted injection zone.

(2) If the director has reason to believe, based upon well records or field observations, that injection fluids are migrating into zones not permitted for injection or into USDWs or to the surface or is causing fluid migration into the USDWs, due to the operation of any Class II well or resulting from a failure of internal or external mechanical integrity of the well, the permit holder shall be required to shut in the well until all necessary corrective work, which may include plugging of the well, is completed.

(k) Internal mechanical integrity shall be maintained in accordance with subsection (o) of this section, below.

(l) Only Class II fluids, as defined in 15 CAR § 275-801(a)(3), and/or freshwater can be injected into a Class II well.

(m) Each well shall have a legible sign placed near the well showing the permit holder and the well name and number and permit number and section, township, and range as shown on the permit in the commission records.

(n)(1) The permit holder of each Class II well shall file a Quarterly Well Status Report on forms prescribed by the director.

(2) The report shall be filed within thirty (30) days after the end of each quarter of a calendar year commencing on January 1 of each year.

(3) The report shall include at a minimum:

(A) Name and permit number of the well;

(B) Names of all injection intervals;

(D) Monthly volumes of fluid injected.

(o) Establishment of internal mechanical integrity.

(1)(A)(i) Internal mechanical integrity must be maintained at all times.

(ii) If internal mechanical integrity is lost, the permit holder shall shut in the well immediately and notify the regional office where the well is located of loss of internal mechanical integrity.

(B) The well shall remain shut in until the necessary remedial action necessary to restore internal mechanical integrity is completed and a new internal mechanical integrity test run and successfully passed.

(2) An internal mechanical integrity test shall be performed:

(A) Prior to initial injection into a newly permitted Class II well;

(B) Prior to initial injection into a Class II well after a change to a newly permitted injection zone;

(C) Prior to resuming injection into any Class II well after any workover of the well involving the resetting or movement of a packer;

(D) Whenever the director has reason to believe, based upon well records or field observation, that the Class II wells may be leaking or improperly constructed; and

(E) At least once every five (5) years measured from the date of the last successful test.

(3) Internal mechanical integrity test.

(A)(i) The following tests shall be performed on Class II wells to establish the internal mechanical integrity of the tubing, casing, and packer of the well.

(ii) The permit holder shall contact the regional office in which the well is located at least forty-eight (48) hours prior to conducting the test to enable an inspector to be present when the test is done.

(iii) Pressure test.

(a) The casing-tubing annulus above the packer shall be tested under the supervision of a commission representative at a minimum pressure differential between the tubing and the annulus of fifty pounds per square inch gauge (50 psig) for a period of thirty (30) minutes.

(b) The casing-tubing annulus starting test pressure shall not be less than three hundred pounds per square inch gauge (300 psig) and may vary no more than ten percent (10%) of the starting test pressure during the test.

(c) The pressure at which the test is to be performed shall be fifty pounds per square inch gauge (50 psig) over the permitted injection pressure, with a maximum of one thousand pounds per square inch gauge (1,000 psig).

(iv) Radioactive tracer survey test. For those wells in which alternative well construction has been approved by the director in accordance with subdivision (f)(2) of this section, above, a radioactive tracer survey may be run in the well at a frequency to be determined by the director to evidence mechanical integrity of the well by demonstrating that the injected fluid is being injected into the approved disposal zone.

(B)(i) Any Class II well which fails an internal mechanical integrity test, or on which an internal mechanical integrity test has not been performed when required, shall be shut in until the well is successfully tested or remedial work is commenced and completed or the well is plugged.

(ii) The necessary work shall be completed and an internal mechanical integrity test successfully completed within ninety (90) days.

(iii) The director may approve up to an additional ninety (90) days, with any greater length of time to be established by the commission upon application by the operator.

(p) If the director has reason to believe, based upon well records or field observation, that any Class II well is causing fluid migration into the USDWs resulting from a failure of internal or external mechanical integrity, the permit holder shall shut in the well until any necessary corrective work is commenced and completed and internal and external mechanical integrity is established.

(q) Class II wells no longer in service for periods greater than twenty-four (24) months shall be plugged or temporarily abandoned in accordance with 15 CAR § 275-207.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: new rule July 17, 2009; amended October 24, 2009; amended June 16, 2019)" Authority: Arkansas Code § 15-71-110

15 CAR § 275-803 Well construction, operating, and reporting requirements for Class II commercial disposal wells {#sec-15-car-275-803 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-803}

15 CAR § 275-803. Well construction, operating, and reporting requirements for Class II commercial disposal wells.

(a) No Class II commercial disposal well, as defined in 15 CAR § 275-801(a)(1), hereinafter referred to as “Class II commercial disposal well”, for which a permit has been issued in accordance with 15 CAR § 275-801, shall be operated until:

(1) Well internal mechanical integrity has been established in accordance with subsection (o) of this section, below; and

(2) An authority for initial commencement of injection operations is issued by the Director of Production and Conservation.

(b)(1) Notice shall be provided to the Oil and Gas Commission regional office where the Class II commercial disposal well is located, prior to performing any well servicing activity, cementing, or any wireline logging activities, so as to allow commission staff to be present to observe the activity.

(c)(1) All well records for newly drilled Class II commercial disposal wells shall be submitted in accordance with 15 CAR § 275-205.

(d) Following issuance of the permit to drill and/or operator a Class II commercial disposal well, an annual fee of one hundred dollars ($100) per well shall be due each July 1 for the life of the well until the well is plugged.

(e) Surface and production casing requirements.

(1) Class II commercial disposal wells shall be cased and cemented in such manner that damage will not be caused to oil and gas resources or any USDW, as defined in 15 CAR § 275-801(a)(5), hereinafter referred to as “USDW”.

(2) Existing wells shall be prohibited for recompletion as a Class II commercial disposal well unless the well had been constructed at the time of original completion in accordance with subdivision (e)(3) of this section, below.

(3) Newly drilled Class II commercial disposal wells.

(A) Set and cement surface casing two hundred fifty feet (250’) below the base of the lowermost USDW, and cement production casing to at least five hundred feet (500’) above the proposed disposal zone or set and cement surface casing fifty feet (50’) below the base of the lowermost formation utilized for a public water system (see 40 C.F.R.) in the area of the Class II commercial disposal well, with a minimum of five hundred feet (500’) of surface casing required, and cement production casing back to the surface.

(B)(i) A cement bond (CBL), gamma ray (GR), and density log (VDL) shall be required to verify the presence of the required casing cement.

(ii) The CBL should indicate at a minimum an eighty percent (80%) bond index over the five-hundred-foot cemented interval.

(f) Tubing and packer requirements.

(1)(A) All injections shall be through tubing and packer.

(B) The packer shall be placed no higher than one hundred feet (100’) above the uppermost perforations or the casing seat in an open hole completion, provided the packer is within the cemented portion of the production casing, provided the packer is no less than seven hundred fifty feet (750’) below the base of the lowermost USDW.

(2) The permit holder shall contact the district office in which the well is located at least twenty-four (24) hours prior to the initial setting or any resetting of the packer in a Class II commercial disposal well to enable an inspector to be present when the packer is set.

(g)(1) The wellhead:

(A) Shall be maintained in a leak-free condition; and

(B) Must have a working pressure gauge in excess of the maximum discharge pressure of the pump.

(h) The injection pressure shall not exceed the maximum injection pressure established in accordance with 15 CAR § 275-801(j)(8).

(i) No change shall be made in the permitted injection zones unless the new zone is permitted in accordance with 15 CAR § 275-801.

(j)(1) Injection fluids shall be confined to the permitted injection zones.

(2) If the director has reason to believe, based upon well records or field observations, that injection fluids are migrating into zones not permitted for injection or into USDWs, or to the surface, or is causing fluid migration into the USDWs, due to the operation of any Class II commercial disposal well or resulting from a failure of internal or external mechanical integrity of the well, the permit holder shall be required to shut in the well until all necessary corrective work, which may include plugging of the well, is completed.

(k) Internal mechanical integrity shall be maintained in accordance with subsection (o) of this section, below.

(l) Only Class II fluids, as defined in 15 CAR § 275-801(a)(3), and/or freshwater can be injected into a Class II commercial disposal well.

(n)(1) The permit holder of each Class II commercial disposal well shall file a Monthly Well Status Report on forms prescribed by the director.

(2) The report shall be filed within thirty (30) days after the end of each month of a calendar year commencing on January 1 of each year.

(3) The report shall include at a minimum:

(A) Name and permit number of the well;

(B) Names of all injection intervals;

(D) Monthly volumes of fluid injected.

(4)(A) In addition, each Class II commercial disposal well facility must keep an accurate log of each shipment of fluids to be disposed.

(B) This log shall include the generator (operator) of the fluid, well name, number, and location or permit number of the well, amount of fluid, and the date the shipment was received.

(o) Establishment of internal mechanical integrity.

(1)(A) Internal mechanical integrity must be maintained at all times.

(B) If internal mechanical integrity is lost, the permit holder shall shut in the well immediately and notify the regional office:

(i) Where the well is located; and

(ii) Of loss of internal mechanical integrity.

(C) The well shall remain shut in until the necessary remedial action necessary to restore internal mechanical integrity is completed and a new internal mechanical integrity test run and successfully passed.

(2) An internal mechanical integrity test shall be performed:

(A) Prior to initial injection into a newly permitted Class II commercial disposal well;

(B) Prior to initial injection into a Class II commercial disposal well after a change to a newly permitted injection zone;

(C) Prior to resuming injection into any Class II commercial disposal well after any workover of the well involving the resetting or movement of a packer;

(D) Whenever the director has reason to believe, based upon well records or field observation, that the Class II commercial disposal well may be leaking or improperly constructed; and

(E) At least once every year measured from the date of the last successful test.

(3) Internal mechanical integrity test.

(A)(i) The following test shall be performed on Class II commercial disposal wells to establish the internal mechanical integrity of the tubing, casing, and packer of the well.

(iii) The casing-tubing annulus above the packer shall be tested under the supervision of a commission representative at a minimum pressure differential between the tubing and the annulus of fifty pounds per square inch gauge (50 psig) for a period of thirty (30) minutes and may vary no more than ten percent (10%) of the starting test pressure during the test.

(iv) The pressure at which the mechanical integrity test is to be performed shall be fifty pounds per square inch gauge (50 psig) over the permitted injection pressure with a maximum of one thousand pounds per square inch gauge (1,000 psig).

(v) The minimum test pressure shall be three hundred pounds per square inch gauge (300 psig).

(B)(i) Any Class II commercial disposal well which fails an internal mechanical integrity test, or on which an internal mechanical integrity test has not been performed when required, shall be shut in until the well is successfully tested or remedial work is commenced and completed or the well is plugged.

(ii) The necessary work shall be completed and an internal mechanical integrity test successfully completed within ninety (90) days.

(iii) The director may approve up to an additional ninety (90) days, with any greater length of time to be established by the commission upon application by the operator.

(p)(1) All commercial facilities must have restricted entry to all nonessential traffic.

(2) A lockable gate must be maintained and shall be locked during all unmanned hours.

(3) Additionally, the director may require a fence to limit entry to the facility.

(q)(1) Permit holders may be required to take periodic samples of the injection fluid and have those samples analyzed at a certified lab.

(2) Samples of the injection fluid may also be taken periodically by a commission representative.

(3) Samples will be checked for compliance with Class II fluids as defined in 15 CAR § 275-801.

(r) If the director has reason to believe, based upon well records or field observation, that any Class II commercial disposal well is causing fluid migration into the USDWs resulting from a failure of internal or external mechanical integrity, the permit holder shall shut in the well until any necessary corrective work is commenced and completed and internal and external mechanical integrity is established.

(s) Class II commercial disposal wells no longer in service for periods greater than twelve (12) months shall be plugged in accordance with 15 CAR § 275-207.

History

Codification Notes: This section as promulgated prior to codification into the Code of Arkansas Rules provided as follows:"(Source: new rule July 17, 2009; amended October 24, 2009)" Authority: Arkansas Code § 15-71-110

Subpart 9

15 CAR § 275-901 Applicability — General provisions — Definitions {#sec-15-car-275-901 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-901}

15 CAR § 275-901. Applicability — General provisions — Definitions.

(a) Applicability. This subpart shall apply to any digital asset mining business as defined by this subpart.

(b) General provisions.

(1) A digital asset mining business in operation before the effective date of this subpart shall be in full compliance with the noise provisions enacted in Arkansas Code § 14-1-604(b)(3) no later than ninety (90) days after this subpart is effective.

(2)(A) No digital asset mining business created after the effective date of this subpart shall operate in Arkansas without first obtaining a permit in accordance with the provisions of this subpart.

(B) An existing digital asset mining business shall not operate in Arkansas without first applying for a permit with the Oil and Gas Commission within ninety (90) days of the date this subpart is promulgated.

(i) Shall operate in accordance with this section, 15 CAR § 275-902, and 15 CAR § 275-903; and

(ii) Shall not operate if its digital asset mining permit application or transfer request is denied or its digital asset mining permit is revoked by the Oil and Gas Commission.

(3) A digital asset mining business may operate in Arkansas if the digital asset mining business:

(A) Is issued a permit from the Oil and Gas Commission in accordance with 15 CAR § 275-902 or 15 CAR § 275-903;

(B) Establishes that the business is not a prohibited foreign-party-controlled business as defined by and in accordance with Arkansas Code § 14-1-606;

(D) Maintains compliance with any rule or rate for utility service provided by or on behalf of a public entity;

(E) Maintains compliance with all applicable state and federal laws, including but not limited to the Arkansas Data Centers Act of 2023, Arkansas Code § 14-1-601 et seq., and Arkansas Code § 23-119-101 et seq.;

(F) Pays all applicable taxes and government fees in acceptable forms of currency; and

(G) Operates in a manner that will not cause any stress on the electric public utility’s generation capabilities or transmission network.

(1) “Applicant” means an entity who makes an application to the Oil and Gas Commission to operate a digital asset mining business;

(2) “Blockchain network” means a group of computers operating and processing together to execute a consensus mechanism to agree upon and verify data in a digital record for the purpose of generating digital assets;

(3) “Digital asset” means cryptocurrency, virtual currency, and natively electronic assets, including without limitation stable coins, nonfungible tokens, and other digital-only assets, that confer economic, proprietary, or access rights or powers;

(4) “Digital asset miner” means an individual who mines for digital assets and holds the digital asset mining business permit issued under this subpart;

(5) “Digital asset mining” means use of electricity to power a computer for the purpose of securing or validating a blockchain network;

(6) “Digital asset mining business” means a group of computers working at a single site that consumes more than one megawatt (1 MW) of electrical energy on an average annual basis for the purpose of generating digital assets by securing a blockchain network;

(7) “Director” means the Director of Production and Conservation;

(8) “Home digital asset mining” means mining digital assets in areas zoned for residential use;

(9) “Legislative body" means the quorum court of a county or the city council, board of directors, board of commissioners, or similar elected governing body of local government;

(10) “Local government” means a county, a city of the first class, a city of the second class, or an incorporated town;

(11) “Mining facility” means the building or other portable building structure where the digital asset mining computers are located;

(12) “Node” means a computational device that contains a copy of blockchain-distributed ledger technology and includes a series;

(13) “Ordinance” means an ordinance, resolution, or other appropriate legislative enactment of a legislative body;

(14) “Person” means an individual or legal entity;

(15) “Regulated entity” means a:

(A) Digital asset miner;

(B) Person owning or operating a mining facility or a digital asset mining business;

(D) Digital asset mining business; and

(16) “Residence” means a permanent dwelling place, unit, or accessory structure.

15 CAR § 275-902 Digital asset mining business requirements {#sec-15-car-275-902 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-902}

15 CAR § 275-902. Digital asset mining business requirements.

(a) No digital asset mining business created after the effective date of this subpart shall operate in Arkansas without first obtaining a permit in accordance with the provisions of this subpart.

(b) An existing digital asset mining business shall not operate in Arkansas without first applying for a permit with the Oil and Gas Commission within ninety (90) days of the date this subpart is promulgated.

(1) Shall operate in accordance with this subpart; and

(2) Shall not operate if its:

(A) Digital asset mining permit application is denied;

(B) Digital asset mining permit is revoked by the Oil and Gas Commission; or

(d) Any digital asset mining permit issued by the Oil and Gas Commission shall not exceed a term of five (5) years from the date of issuance.

(e) The applicant shall file a completed initial permit application or renewal application, utilizing a form prescribed by the Director of Production and Conservation, which shall contain the following:

(1) A completed organization report on a form prescribed by the Director of Production and Conservation;

(2) Documentation establishing that the digital asset mining business is currently in good standing status with the Secretary of State;

(3) A survey plat of the property boundaries on which the mining facility will be located that shows the location of:

(A) The mining facility; and

(B) All power and water lines and other utility services providing service to the mining facility;

(4) A current topographic map, aerial or satellite imagery, or other type of map that shows the location of the mining facility and the distance of all surrounding residences within a two-mile radius of the mining facility;

(5) A copy of an agreement with the entity supplying the electric power to the mining facility that certifies that the electric usage by the mining facility will not negatively impact the local electric grid or increase electric costs to the local customers;

(6) A copy of an agreement with the local water utility or private water well owner supplying water to the mining facility that certifies that the water usage by the mining facility will not negatively impact the local water supply and water rates of the local customers;

(7) A notarized affidavit certifying that the digital asset mining business operating the mining facility is not a prohibited foreign-party-controlled business and is in compliance with Arkansas Code § 14-1-606; and

(8) A technical description, including schematics and engineering specifications, of the system proposed to be utilized or the local government location approvals necessary to comply with noise-reduction techniques in accordance with Arkansas Code § 14-1-604(b)(3), including without limitation schematics or specifications that demonstrate:

(A) The digital asset mining business will use a liquid cooling or submerged cooling process for the mining facility;

(B) The mining facility shall be fully enclosed around all sides, including above and below the equipment producing the noise, with material that is reasonably calculated by industry standards to reduce noise emissions to a level that is acceptable to a reasonable person under similar circumstances; or

(C) Upon approval by the local government, the mining facility may use a passively cooled premanufactured container without additionally enclosing the container in a complete envelope if the mining facility is located in or relates to an area that is:

(i) At least two thousand feet (2,000’) away from the nearest residential or commercial use structure; or

(ii) Zoned for industrial use or an otherwise approved use.

(f)(1) Additionally, the digital asset mining business shall:

(A)(i) Publish general public notice of the application no more than ten (10) days prior to filing the application with the Oil and Gas Commission in a newspaper having a general circulation in the county, or in each county if there shall be more than one (1), within a one-mile radius from where the proposed mining facility is located.

(ii) In addition, the public notice should be large font and surrounded by a printed border to highlight the published notice; and

(B) Provide notice by mailing, no more than ten (10) days prior to filing the application with the Oil and Gas Commission, via certified mail, FedEx, United Parcel Service, or other method that provides proof of mailing and delivery to the following persons and entities:

(i) Any local government having jurisdiction over the area where the mining facility is proposed to be located;

(ii) The Division of Environmental Quality;

(iii) All surface owners of record within one (1) mile of the mining facility; and

(iv) Any other persons as determined by the Director of Production and Conservation.

(2) The notice given by the digital asset mining business shall contain the following:

(A) The name and address of the applicant;

(B) A brief description of the nature and purpose of the application;

(D)(i) A statement that explains that a copy of the application and exhibits may be obtained from the Oil and Gas Commission or the digital asset mining business.

(ii) When the Oil and Gas Commission receives a request for a copy of the application from an interested party, the Oil and Gas Commission may direct the digital asset mining business to deliver the application to the interested party.

(iii) The cost of such notice and mailing of the application shall be paid for by the digital asset mining business; and

(E) A statement that explains that all comments or objections regarding the application must be in writing and submitted to the Oil and Gas Commission prior to the expiration of the forty-five-day notice period specified in subdivision (g)(1) of this section.

(g) Objections.

(1)(A) Objections to the application must be received by the Director of Production and Conservation within forty-five (45) days after the publication date of the notice specified in subdivision (f)(1)(A) of this section or the postmark date of the notice specified in subdivision (f)(1)(B) of this section, whichever date is later.

(B) If an objection is received, the application shall be referred to the Oil and Gas Commission for determination without imposition of a filing fee, and a hearing shall be conducted in accordance with 15 CAR §§ 275-101 and 275-102 and all other applicable hearing procedures.

(2)(A) If a timely objection is not received by the Director of Production and Conservation and the application is deemed administratively complete, the permit shall be issued unless the Director of Production and Conservation deems it necessary to refer the application to the Oil and Gas Commission for determination for the purpose of:

(i) Protecting public health and safety;

(ii) Protecting the environment; or

(iii) Preventing damage to property.

(B) No filing fee shall be assessed by the Oil and Gas Commission for any hearing set pursuant to this referral by the Director of Production and Conservation.

(h) If the applicant satisfies the requirements of all applicable statutes and this subpart, a permit shall be issued unless:

(1) The applicant has falsified or otherwise misstated any material information on or relative to the permit application;

(2) The applicant is or was an owner, officer, director, partner, member, or manager of a digital asset mining business, or other person with an interest in the entity exceeding five percent (5%), that has failed to:

(A) Abate any outstanding violations of statutes or rules; or

(B) Comply with orders of the Oil and Gas Commission as specified in a final administrative decision of the Oil and Gas Commission in accordance with the provisions of this subpart;

(3) The applicant is a current permit holder that has failed to:

(A) Abate outstanding violations of any statutes or rules; or

(B) Comply with orders of the Oil and Gas Commission as specified in a final administrative decision of the Oil and Gas Commission in accordance with the provisions of this part; or

(4) If the Director of Production and Conservation determines that the applicant or permit holder, or an owner, officer, director, partner, member, or manager or other person with an interest exceeding five percent (5%) in the digital asset mining business, has a history of violating any applicable statutes, Oil and Gas Commission rules, permit condition, or order of the Oil and Gas Commission, the Arkansas Pollution Control and Ecology Commission, or any other state or federal regulatory agency, the permit shall be denied.

(i) If a permit is denied pursuant to subsection (h) of this section, the applicant may request a hearing with the Oil and Gas Commission on this determination, in accordance with 15 CAR §§ 275-101 and 275-102 and other applicable hearing procedures.

(j) Digital asset mining permit revocation procedures.

(1) The Director of Production and Conservation may revoke a digital asset mining permit if the:

(A) Permit holder fails to meet permit conditions as specified in the digital asset mining permit;

(B) Digital asset mining permit was issued in error;

(D) Permit holder falsified or otherwise misstated any material information in the application form.

(2)(A) The Director of Production and Conservation shall notify the permit holder in writing of the revocation of the digital asset mining permit.

(B) Following the notice of revocation, the permit holder shall have thirty (30) days from the date of the digital asset mining permit revocation notice to appeal the Director of Production and Conservation’s decision to revoke the digital asset mining permit.

(C) If the permit revocation is appealed, a hearing contesting the permit revocation shall be conducted in accordance with 15 CAR §§ 275-101 and 275-102 and other applicable hearing procedures.

(D) Operation of the mining facility may not commence or continue during the appeal process.

(E) A revocation of a digital asset mining permit for which an appeal has not been timely filed shall become a final administrative decision of the Oil and Gas Commission.

15 CAR § 275-903 Digital asset mining business permit transfer procedures {#sec-15-car-275-903 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-903}

15 CAR § 275-903. Digital asset mining business permit transfer procedures.

(a) Definitions. As used in this section:

(1) “Current permit holder” means the person required to hold the permit or to whom the permit was issued and who is the owner of the digital asset mining business and possesses the full rights and responsibilities for operating the business in accordance with applicable Arkansas law or rule or order of the Oil and Gas Commission;

(2) “New permit holder” means the person acquiring the digital asset mining business and who obtains the full rights and responsibilities for operating the business and possessing the permit in accordance with applicable Arkansas law or rule or order of the commission; and

(3) “Transfer” means any voluntary or involuntary:

(A) Assignment;

(B) Devise;

(D) Transfer;

(E) Takeover;

(F) Buyout;

(G) Merger;

(H) Sale;

(I) Conveyance; or

(J) Other transfer of any kind.

(b) The provisions of this section apply to all transfers of the interest of the permit holder, including but not limited to:

(1) A change of ownership of the right to operate the digital asset mining business;

(2) A change of ownership or membership in the corporate entity that operates the digital asset mining business or a change in the designation of the owner or operator under an operating agreement or other similar agreement;

(3) An action of the owners of separate interests who designate a new owner to be permit holder; or

(4) A change required by the appointment, by a court of competent jurisdiction, of a trustee or a receiver to exercise custody and control over the digital asset mining business.

(c) Notification of a transfer shall be given to the Director of Production and Conservation, or his or her designee, by the current permit holder on a form prescribed by the director.

(d) The notification shall be signed by the current permit holder and the new permit holder, or by authorized representatives specified on the commission organization report filed in accordance with 15 CAR § 275-902(e)(1).

(e) Prior to the director, or his or her designee, approving the transfer request, the new permit holder must:

(1) Be authorized to do business within the State of Arkansas; and

(2) Comply with all applicable provisions of state law and 15 CAR § 275-902.

(f) A transfer to a new permit holder shall be denied by the director, or his or her designee, if:

(1) The new permit holder has not fully satisfied all applicable statutory and rule requirements;

(2) The commission has not approved the transfer in accordance with subsection (e) of this section;

(3) The new permit holder has falsified or otherwise misstated any material information on or relative to the transfer application; or

(4) No further permits or authorities may be issued in accordance with subsection (e) of this section.

(g) The new permit holder shall assume compliance with all existing permit obligations and be responsible for complying with all regulatory requirements associated with the permit.

(h)(1) If the digital asset mining business or mining facility is in violation of any rules, statutes, or orders of the commission at the time of the transfer request to the new permit holder, the transfer request shall be denied pending abatement of all violations by the current permit holder.

(2)(A) However, if the new permit holder, after being notified of the violation or violations, agrees in writing to the transfer approval including conditions to abate all violations, the transfer may be approved by the director, or his or her designee, in accordance with this subpart.

(B) Failure to abate the violations within the time period specified by the director, or his or her designee, may result in revocation of the transfer approval and other applicable enforcement actions in accordance with 15 CAR § 275-104.

(i)(1) The current permit holder is not responsible for any regulatory violation caused by the actions of the new permit holder during the permit transfer process.

(2) However, if the transfer is denied by the director, or his or her designee, the current permit holder will assume all responsibility for any violations caused by the new permit holder.

(3) Nothing in this subsection shall affect the contractual rights and obligations between the person or entity transferring the permit and the person or entity acquiring the permit.

(j) The transfer request shall not affect the rights of the commission or any obligation or duty of the current permit holder arising under any applicable Arkansas law or rule or order of the commission.

(k)(1) The director shall notify the current and new permit holder of the transfer approval or denial in writing.

(3) A transfer request approval or denial for which a timely appeal has not been filed shall become a final administrative decision of the commission.

(l) Permit transfer revocation procedures.

(1) The director may revoke a digital asset mining business permit transfer approval if the:

(A) Permit holder fails to comply with conditions as specified in the permit transfer approval;

(B) Permit transfer approval was issued in error; or

(2)(A) The director shall notify the permit holder of the digital asset mining business permit transfer revocation in writing.

(B) Following the revocation notice, the permit holder is required to cease operation of the mining facility.

(C) The permit holder shall have thirty (30) days from the date of the permit transfer revocation to appeal the director’s decision to revoke the transfer approval in accordance with 15 CAR §§ 275-101 and 275-102 and other applicable hearing procedures.

(D) Operation of the mining facility may not commence or continue during the appeal process.

(E) A revocation of a permit transfer approval for which an appeal has not been timely filed shall become a final administrative decision of the commission.

15 CAR § 275-904 Digital asset mining business enforcement procedures {#sec-15-car-275-904 omnilex-key=us-ar-regs-official--title-15-part-275--15 CAR § 275-904}

15 CAR § 275-904. Digital asset mining business enforcement procedures.

(a) Any regulated entity operating a digital asset mining business is subject to the enforcement provisions of this section and the Arkansas Data Centers Act of 2023, Arkansas Code § 14-1-601 et seq., and the digital asset mining provisions of Arkansas Code § 23-119-101 et seq.

(b) Notice of Noncompliance.

(1) A Notice of Noncompliance may be issued when any regulated entity is not in compliance with any requirement of this subpart, the Arkansas Data Centers Act of 2023, Arkansas Code § 14-1-601 et seq., or Arkansas Code § 23-119-101 et seq., and:

(A) The noncompliance was not caused by the regulated entity’s deliberate action;

(B) Any action necessary to abate the noncompliance was commenced immediately and was or will be completed within a specified date, as established by the Director of Production and Conservation, or his or her designee, not to exceed thirty (30) days from the date that the regulated entity was determined to be out of compliance; and

(C) The noncompliance has not caused and cannot reasonably be expected to cause significant harm to public health and safety or damage to property.

(2)(A) The Notice of Noncompliance shall be documented in writing and delivered via first class mail to the regulated entity or to the regulated entity’s representative as reported on the Oil and Gas Commission organization report.

(B) The written notification shall indicate the:

(i) Nature and circumstances of the noncompliance; and

(ii) Time within which and the means by which the noncompliance is to be abated.

(3) If abatement is not completed as specified in the written notification, the director, or his or her designee, may issue a formal Notice of Violation in accordance with subsection (c) of this section.

(4) The provisions of this subsection shall not apply to the following types of incidents, which may require a Notice of Violation to be issued in accordance with subsection (c) of this section:

(A) Conducting any regulated activity prior to issuance of the appropriate commission permit; or

(B) Failure to bring an existing mining facility into compliance with Arkansas law or 15 CAR § 275-902.

(1)(A) A Notice of Violation may be issued by the director, or his or her designee, when any regulated entity is in violation of any requirements of the Arkansas Data Centers Act of 2023, Arkansas Code § 14-1- 601 et seq., Arkansas Code § 23-119-101 et seq., or rules, orders, or any permit conditions of the commission.

(B) Unless otherwise determined by the commission after notice and a hearing, a regulated entity shall not be compelled by the commission to abate violations of the Arkansas law, rules, or orders or any permit conditions of the commission in the absence of the issuance of an underlying Notice of Violation.

(2) The Notice of Violation shall be in writing and contain:

(A) A statement regarding the nature of the violation, including a citation to the specific section of the Arkansas Data Centers Act of 2023, Arkansas Code § 14-1-601 et seq., or Arkansas Code § 23-119-101 et seq., or rules, orders, or any permit conditions of the commission alleged to have been violated;

(B) The suggested action needed to abate the violation, including any appropriate remedial measures to prevent future violations;

(D) A notice of any civil penalties, as specified in subsection (e) of this section, that the director will request the commission issue.

(3) The Notice of Violation may include a cessation requirement, or a separate cessation order may be issued for the following types of violations:

(A) Operating a digital asset mining business or mining facility without a commission permit;

(B) Improper disposal or discharge of cooling fluids; or

(4) The director, or his or her designee, shall:

(A) Send via certified mail the Notice of Violation to the regulated entity charged with the violation or violations or the regulated entity’s representative as reported on the commission organization report; or

(B) Provide personal delivery of a copy of the notice to the regulated entity or the regulated entity’s representative.

(5)(A) The regulated entity charged with the violation or violations may request a director’s review of the Notice of Violation and provide the director, in writing, any information in mitigation of the violation or violations within thirty (30) calendar days of the mailing or personal delivery of the original Notice of Violation, unless a shorter time period is specified in the Notice of Violation for instances where there is a condition that creates an imminent danger to the health or safety of the public or threatens significant environmental harm or damage to property.

(B) Such written information may include a proposed alternative to the required action needed to abate the violation or violations.

(6) During the review, the director may consider any of the following criteria in reaching a final director’s decision regarding the violation or violations:

(A) The regulated entity’s history of previous violations, including violations at other locations and under other permits;

(B) The seriousness of the violation, including any irreparable harm to public health and safety, the environment, or damage to property;

(D) The existence of any additional conditions or factors in aggravation or mitigation of the violation, including information provided by the regulated entity.

(7) Upon completion of the review, the director shall issue a final director’s decision to:

(A) Affirm the violation;

(B) Vacate the violation;

(D) Establish probationary or permanent modification or conditions to any underlying permit related to the violation, which may include special monitoring or reporting requirements; or

(E) Enter into a settlement agreement to extend the amount of time provided to complete remedial actions necessary to abate the violations or reduce the amount of the requested assessed civil penalty.

(8)(A) The final director’s decision shall be delivered to the regulated entity, or the regulated entity’s representative as reported on the commission organization report, via first class mail.

(B) The final director’s decision may be appealed to the commission by filing an application in accordance with 15 CAR §§ 275-101 and 275-102 and other applicable hearing procedures.

(C) The director must receive the application to appeal the final director’s decision within thirty (30) days of the mailing of the final director’s decision.

(D) The application shall state the reason for the appeal, and the application shall be scheduled to be heard by the commission in accordance with 15 CAR §§ 275-101 and 275-102 and other applicable hearing procedures.

(9) A Notice of Violation for which a director’s review has not been requested shall become a final administrative decision of the commission thirty (30) days following the mailing of the Notice of Violation.

(10) A final director’s decision not appealed to the commission within thirty (30) days of the mailing of the final director’s decision shall become a final administrative decision of the commission.

(11)(A) All violations specified in a Notice of Violation that have become a final administrative decision in accordance with subdivision (c)(9) of this section, included in a final director’s decision that has become a final administrative decision of the commission in accordance with subdivision (c)(10) of this section, or included in an order of the commission, shall be fully abated within the time frame specified in the original Notice of Violation, final director’s decision, or order of the commission.

(B) No further permits or authorization shall be issued to the regulated entity until all outstanding violations specified in a Notice of Violation that has become a final administrative decision in accordance with subdivision (c)(9) of this section, a final director’s decision that has become a final administrative decision of the commission in accordance with subdivision (c)(10) of this section, or by order of the commission have been fully abated.

(d) In addition to the issuance of a Notice of Violation, the director and the commission may initiate investigative or enforcement proceedings upon receipt of a complaint by:

(1) Initiating a referral to the Attorney General for enforcement in accordance with Arkansas Code § 14-1-606;

(2) Making reasonable investigations and inspections;

(3) Examining properties, leases, papers, books, and records;

(4) Holding hearings;

(5) Requiring the keeping of records and the making of reports;

(6) Taking such action as may be reasonably necessary to enforce state law and commission rules, including compliance with the Arkansas Data Centers Act of 2023, Arkansas Code § 14-1-601 et seq., and Arkansas Code § 23-119-101 et seq.

(e) Civil penalties.

(B) If a civil penalty is requested by the director, the regulated entity may voluntarily agree to the assessment and pay the civil penalty as requested or modified by the director, or the director or his or her designee may file an application, in accordance with 15 CAR §§ 275-101 and 275-102 and other applicable hearing procedures, to request the issuance of the requested civil penalty by the commission.

(C) The maximum amount of the director’s requested civil penalty shall be computed as provided in subdivisions (e)(2), (3), and (4) of this section.

(D) However, the commission is not bound by the director’s request or the amounts provided below and may impose civil penalties of up to five thousand dollars ($5,000) per day per violation as permitted by statute.

(2)(A) Administrative violations are defined as failure to file required reports and forms and to provide required notices.

(B) The director may request the assessment of up to two thousand five hundred dollars ($2,500) per administrative violation, plus up to five hundred dollars ($500) per day for each day the violation remains unabated after the specified compliance date.

(C)(i) The per-administrative-violation civil penalty request shall be calculated as follows:

(a) No previous violation of the same rule, one thousand dollars ($1,000);

(b) One (1) previous violation of the same rule, one thousand five hundred dollars ($1,500); and

(ii) The time frame used for determining previous violations shall be limited to the regulated entity’s violation record for the preceding five (5) full calendar years before the issuance of the violation.

(3)(A) Operating violations are defined as failure to maintain compliance with the commission’s digital asset mining rules.

(B) These violations include, but are not limited to, regulated activities such as:

(i) Operating a mining facility without the proper permit or transfer of ownership; and

(ii) Failure to maintain a mining facility in compliance with this subpart.

(C) The director may request the assessment of up to five thousand dollars ($5,000) per operating violation plus up to two thousand five hundred dollars ($2,500) per day for each day the violation remains unabated after the specified compliance date, with the exception that operating violations as specified in statute are limited to a maximum of five thousand dollars ($5,000) per day per operating violation.

(D)(i) The per-operating-violation civil penalty shall be calculated as follows:

(a) No previous violation of the same rule, two thousand five hundred dollars ($2,500); and

(b) One (1) previous violation of the same rule, five thousand dollars ($5,000).

(f) All civil penalties assessed and paid to the commission in accordance with this subpart shall be deposited into the commission operating fund.