Current through Register Vol. 49, No. 2, February 2024
FOREWORD
This publication contains the Commission Rules of statewide
application. Special rules pertaining to individual oil, gas, or salt water
fields and pools are not included but should be consulted.
In using this publication one should be aware that there is a
considerable body of statutory law in Arkansas that must be consulted in
evaluating an oil and gas matter.
This statutory law is not set out in full herein. The reader
should refer to Arkansas Code, Annotated, Title 15, Chapter
72, for the statutory law.
GENERAL RULE A - ADMINISTRATIVE
RULE A-1:
REPEALED
Rule Repealed Effective October 19, 2018 in accordance with Act
781 of 2017
RULE A-2:
GENERAL HEARING PROCEDURES
a) Execution and Filing
1) All applications, except for applications
filed by the Director, shall be in writing and state the interests of the
application and the general nature of the order requested. Fourteen copies of
the application, including exhibits, shall be filed with the Commission
Director's office located in Little Rock, Arkansas ("Director's Office"). The
application shall be deemed filed when it is received by the Director's
Office.
2) All fourteen (14) copies
of the applications, including exhibits, except for those filed by the
Director, must be received in the Directors Office at least twenty (20) days
prior to the first day of regularly scheduled hearing. If the applicant or
his/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) Every
application shall be signed by the applicant or his/her representative and
his/her address shall be stated thereon. The signature of the applicant or
his/her representative constitutes a certificate by him/her that he/she has
read the petition and that to the best of his/her knowledge, information and
belief there is good ground to support the same.
4) Unless otherwise provided by General Rule
of the Commission, each application, except for applications filed by the
Director, shall be accompanied by a five hundred dollar ($500.00) filing fee
made payable to the Arkansas Oil and Gas Commission.
5) The applicant shall also submit a check
payable to the Arkansas 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 address are known as well as addresses for other persons
that the applicant seeks to provide a copy of the order. 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. If the address of the person is unknown, the
Applicant shall provide a statement to that affect. 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 subsections a) 1) through 4) above, 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 facts, data, records or other information.
8) Amendments may be filed at the time of the
hearing. However, any amendments filed prior to the hearing date shall be
submitted at least ten (10) days prior to the hearing date, and contain a
written statement or a clear indication as to what the amendment is being
amended. 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) The Applicant shall prepare a notice of
hearing which shall be issued in the name of the Arkansas Oil and Gas
Commission. Such notice shall include a statement pertaining to the legal
authority for the hearing; the name of the applicant; the legal description of
the property or unit; a statement of the requested action; a listing of
interested parties; the time, date and location of the hearing; the Commission
assigned docket number; and the contact information of the Commission offices.
The notice shall also state that 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 that thereafter such person shall be
deemed a party of record in the proceeding.
2) Unless otherwise provided by the Brine Act
found in Ark. Code Ann. §
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 U.S. 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.
c) Emergency Hearings
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. 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 days from its
effective date in accordance with the Brine Act found in Ark. Code Ann. §
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) Pre-Hearing
Conferences
1) Upon his/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) Pre-hearing conferences may be held by
telephone conference if such procedure is acceptable to all parties.
e) Hearings
1) 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. The Hearing Officer shall take all necessary
actions to avoid delay, to maintain order and to develop a clear and complete
record, and shall 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;
C) To regulate
the course of the hearing and the conduct of the parties and their counsel
therein;
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) 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.
The Hearing Officer may require that relevant documents be produced to any
party of record on his/her own motion or for good cause shown on motion of any
party of record.
2) Every
person appearing shall enter his/her appearance by stating his/her name and
address. Thereafter, such person shall be deemed a party of record.
3) All participants in the hearing shall have
the right to be represented by an attorney licensed to practice law in the
State of Arkansas. An attorney appearing in a representative capacity in any
proceeding hereunder shall file a written notice of appearance identifying his
or her name, address and telephone number, and identifying 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/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 documents necessary to present the issues to be
heard, notices, proof of publication and orders previously entered in the
cause.
B) Rulings may be made by
the Hearing Officer on any pending motions.
C) Any other preliminary matters appropriate
for disposition prior to presentation of evidence.
7) Every hearing shall be conducted in
accordance with the Commission's rules and applicable laws of this
State.
f) Evidence
1) Admissibility: A party shall be entitled
to present his/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. Any oral or documentary evidence may be
received, but the presiding Hearing Officer may exclude evidence which is
irrelevant, immaterial or unduly prejudicial or repetitious. However, the
erroneous ruling on the admissibility of evidence shall not of itself
invalidate any rule or order.
2)
Official Notice: 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. In addition, notice may be taken of
generally recognized technical or scientific facts within the Commission's
specialized knowledge.
3) Order of
Proof: The applicant shall open the proof. Other parties of record shall be
heard immediately following the petitioner. The Hearing Officer or Director or
his/her designee, as well as any Commissioner may examine any witnesses. In all
cases, the Hearing Officer shall designate the order of proof and 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 10 days
after the close of the hearing or within 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
The Commission shall provide a certified court reporter to take
down the testimony and preserve a record of all proceedings at the hearing. Any
person testifying shall be required to do so under oath. 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
Any hearing may be postponed or continued for due cause by the
Hearing Officer upon his/her own motion or upon the motion of a party to the
hearing. 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. 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. The Applicant may postpone or continue
the hearing of an application for three consecutive regularly scheduled
Commission meetings without prior approval of the Hearing Officer. 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 re-file in accordance with applicable General Rules in order for an
application to be scheduled for a hearing.
i) Default - Failure to Appear.
If a party, after proper service of notice, fails to appear at
the pre-hearing 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. If the failure to appear at such pre-hearing 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 pre-hearing conference
or hearing, the Hearing Officer may continue or post-pone the pre-hearing
conference or hearing. Emergency situations include sudden unavailability of
counsel, sudden illness of a party or his representative, or 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 General Rule
A-3 b) 2) A) though G);
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(s) where the well is located (as defined in Section (a)(2) of General Rule
B-3), including any acreage within the unit(s) subject to leases or other
agreements with a fee mineral owner covering lands located in more than one
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 $7,500.00 for a
drilling well rate and $750.00 dollars for a producing well when the proposed
well is a dry natural gas well; or
ii) Not to exceed more than $4,500.00 for a
drilling well rate and $450.00 dollars 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 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(s) 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 time no earlier than ten (10) days prior to filing the
application, and no later than the date of filing the application.
H) 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. Each objection must
be made in writing and filed with the Director. 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 (15) day time period after receipt of the application. 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
General Rules A-2 and A-3, and other applicable hearing requirements, except
that no additional fee is required.
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) 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.
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(s) for referral to the full Commission for
determination. If the application is referred under this section, the applicant
shall file a request for a hearing, in accordance with General Rules A-2 and
A-3, 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 (15) 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 subsection j)1)H) above, 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 of 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
C) At least five (5) votes cast
must be in favor of the motion outlining the proposed order.
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 subparagraphs 1) A) through
C) above, and no subsequent or substitute motion receives the votes required in
subparagraphs 1) A) through C) above, 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
subparagraph i) 2) above, the Commission shall enter an order of denial, which
may be appealed as a final decision under the Arkansas Administrative
Procedures Act found in Ark. Code Ann. §
25-15-201
et. seq.
4)
Nothing in this subparagraph shall limit the Commission's authority to continue
any application for due cause.
l) Commission's Order--Final Administrative
Decision
Within 30 days of the close of the hearing record, the Commission
shall issue findings of fact, conclusions of law and final administrative
decision of the Commission signed by the Director. The Commission shall have
continuing jurisdiction for the purposes of enforcement, and/or modifications
or amendments to the provisions of all orders. Any appeals shall be governed by
the Administrative Procedures Act found in Ark. Code Ann. §
25-15-201
et. seq.
m) Notice of Order--Recordation
Within 30 days after an order has been issued, a copy of such
order shall be mailed by the Commission to each interested party at his/her
last known address or his/her attorney of record, and filed in accordance with
the Administrative Procedures Act found in Ark. Code Ann. §
25-15-201
et. seq.
n) Official Record
In every case of adjudication, the official record shall be
complied in accordance with the Administrative Procedures Act found in Ark.
Code Ann. §
25-15-201
et. seq.
(Source: 1992 rule book; amended April 13, 2008; amended June 5,
2009; amended October 24, 2009; amended July 1, 2016)
RULE A-3:
ADDITIONAL REQUIREMENTS FOR SPECIFIC TYPES OF
HEARINGS
a) Abandoned
Well and Emergency Response Hearings
1) Unless
otherwise specified below, General Rule A-2 shall apply to all abandoned well
and emergency response hearing proceedings pursuant to Ark. Code Ann. §
15-72-217.
2) The Director shall only provide notice to
the permit holder named in the application, in accordance with General Rule A-2
(b) (2).
3) The Director shall have
the burden of proof at the hearing. A decision shall be supported by a
substantial evidence standard.
b) Integration Hearings
1) Unless otherwise specified below, General
Rule A-2 shall apply to all drilling unit integration proceedings heard by the
Commission.
2) Commencement of
Action
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 Ark. Code Ann.
§
15-72-302
and §
15-72-303.
The application for an order integrating interests shall contain the
following:
A) The name and address of
the applicant;
B) The applicant's
reasons for desiring to integrate the separately owned interests;
C) A legal land description of the drilling
unit sought to be established;
D) A
geologic report of the area where the proposed drilling unit is to be located
indicating the potential presence of reservoirs;
E) If the application is for the integration
of an exploratory drilling unit, as contemplated by Ark. Code Ann. §
15-72-302:
i) 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;
ii) 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;
F) If the application is for the integration
of an established drilling unit, as contemplated by Ark. Code Ann. §
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;
G) Unleased mineral owners.
i) 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:
aa) Due diligence, regarding non-industry
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.
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.
bb) Due diligence, regarding industry owners
(person 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.
ii) 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(s) where the well is located (as defined in Section (a)(2) of General
Rule B-3), including any acreage within the unit(s) subject to leases or other
agreements with a fee mineral owner covering lands located in more than one
unit. If this information changes prior to the hearing, the Applicant shall
inform the Commission of any changes. 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(s) where the well is located (as defined in Section
(a)(2) of General Rule B-3), including any acreage within the unit(s) subject
to leases or other agreements with a fee mineral owner covering lands located
in more than one unit.
H) 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.
I)
Any other information relevant to protect correlative rights of the parties
sought to be affected by the order.
c) Appeal of Director's Decision.
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, General Rule A-2 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 and fifty dollar ($250.00)
filing fee.
d)
Exceptional Well Location
1) Unless otherwise
specified below, General Rule A-2 shall apply to all hearings for an
application which has been referred to the Commission in accordance with
General Rule B-40, or for which General Rule B-40 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(s), which shall be encroached upon by the exceptional well
location.
3) If the application has
been referred to the Commission in accordance with General Rule B-40, no
application fee is required to be submitted with the application.
e) Authority to Commingle and
Additional Completions
1) Unless otherwise
specified below, General Rule A-2 shall apply to all hearings for which the
applicant has requested a hearing for an application which has been denied in
accordance with General Rule D-18 or General Rule D-19, or for which General
Rules D-18 or D-19 are not applicable.
2) If the applicant requests the hearing in
accordance with General Rule D-18, 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 General Rule D-19, 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, General Rule A-2 shall apply to all hearings for the
creation of field rules, as provided by General Rule B-38.
2) The application shall include proof of
notice to each owner, as defined in Ark. Code Ann. §
15-72-102(9),
within the proposed unit(s) in which the well(s) is/are located and within all
units offsetting the boundary line or lines of the proposed unit(s).
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 completion report of the discovery and other
wells located within the proposed field, a type geophysical log from a well(s)
in the proposed field and a structure and isopach map of the productive zone(s)
within the proposed field.
(Source: 1992 rule book; amended April 13, 2008; amended December
14, 2008; amended July 17, 2009; amended July 1, 2016)
RULE A-4:
DEFINITIONS
Unless the context otherwise requires, the words defined shall
have the following meaning when found in these rules, to-wit:
ATMOSPHERIC PRESSURE --
shall mean the pressure of air at the sea level, equivalent to about 14.7
pounds to the square inch.
BALANCE -- (Gas) shall mean
an instrument used for determining the specific gravity of gases by weighing
methods.
BAROMETRIC PRESSURE --
shall mean the pressure or weight of air determined by the use of a barometer
at a given point.
"BARREL" or "BARREL OF OIL"
-- shall mean 42 United States gallons of oil at a test of 60 degrees
Fahrenheit, with deductions for the full percent of basic sediment, water and
other impurities present, ascertained by centrifugal or other recognized and
customary test.
BLOW-OUT -- shall mean a
sudden or violent escape of crude oil or natural gas, as from a drilling well,
when high formation pressure is encountered.
BLOW-OUT PREVENTER -- shall
mean a heavy casing head control filled with special gates or discs which may
be closed around the drill pipe, or which completely closes the top of the
casing if the pipe is withdrawn.
BOTTOM HOLE PRESSURE --
shall mean 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. 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.
CASING PRESSURE -- shall
mean the pressure built up between the casing and tubing when the casing and
tubing are packed off at the top of the well.
CASINGHEAD GAS -- shall
mean any gas or vapor, or both gas, and vapor, indigenous to an oil stratum and
produced from such stratum with oil.
CHRISTMAS TREE -- shall
mean 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."
CIRCULATION -- shall mean
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.
COMBINATION WELL -- shall
mean a well productive of both oil and gas in commercial quantities from the
same common source of supply and which has sufficient natural gas pressure to
cause the gas to enter a pipe line carrying more than atmospheric
pressure.
COMMISSION -- shall mean
the Arkansas Oil and Gas Commission.
COMMON SOURCE OF SUPPLY --
shall mean 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. Any oil or gas field or
part thereof which comprises and includes any area which is underlaid, or which
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.
CONDENSATE -- shall mean
the liquid produced by the condensation of a vapor or gas either after it
leaves the reservoir or while still in the reservoir. Condensate is often
called Distillate, Drips, White Oil, Etc.
CONNATE WATER -- shall mean
water which was deposited with the deposition of solid sediments in an oil or
gas reservoir and which has not, since its deposition, existed as surface water
at atmospheric pressure.
CONSERVATION -- shall mean
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.
CONTROLLED OIL FIELD --
shall mean 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.
CONTROLLED GAS FIELD --
shall mean 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.
CONTROLLED PRODUCTION --
shall mean the production of oil or gas or both oil and gas from a controlled
oil or gas field.
CORE HOLE -- shall mean a
hole drilled below the fresh water level for obtaining geological and
structural information without penetrating a known producing formation in the
area.
CRUDE OIL -- shall mean
petroleum oil, and other hydrocarbons, regardless of gravity, which are
produced at the well in liquid form by ordinary production methods, and which
are not the result of condensation of gas before or after it leaves the
reservoir.
CUBIC FOOT OF GAS -- shall
mean the volume of gas contained in one cubic foot of space at the standard
pressure base and the standard temperature base. The standard pressure base
shall be 14.65 pounds per square inch absolute and the standard temperature
base shall be 60o Fahrenheit.
DAY -- shall mean a period
of twenty-four (24) consecutive hours from 7:00 a.m. one day to 7:00 a.m. the
following day.
DEVELOPMENT -- shall mean
any work which actively looks toward bringing in production, such as erecting
rigs, building tankage, drilling wells, etc.
DIFFERENTIAL PRESSURE --
shall mean the difference between the tubing pressure and the flow-line
pressure; the drop flow-line pressure; the drop in pressure of the fluid in
passing through the flow-nipple or choke; in the case of an orifice meter, the
difference of the pressures on the upstream and the down-stream sides of the
orifice; a pressure measured with a differential gauge or with a manometer
(U-tube); any difference in pressure.
DISTILLATE -- shall mean 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. Condensate is commonly referred to as
distillate.
DIVISION ORDER -- shall
mean a written statement, dated, duly signed by the owners and delivered to the
purchaser, certifying and guaranteeing the interests of ownership of the
production and directing payments according to those interests.
DRY GAS -- shall mean
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.
EDGE WATER -- shall mean
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.
FIELD -- shall mean the
general area which is underlaid or appears to be underlaid by at least one
pool; and "field" shall include the underground reservoir or reservoirs
containing crude petroleum oil or natural gas, or both. The words "field" and
"pool" mean the same thing when only one underground reservoir is involved;
however, "field" unlike "pool," may relate to two or more pools.
FLOWING WELL -- shall mean
a well from which oil or gas flows naturally without pumping or other means of
artificial lift.
GAS -- shall mean the
natural gas obtained from gas or combination wells regardless of its chemical
analysis.
GAS ALLOWABLE -- shall mean
the amount of natural gas authorized to be produced by order of the
Commission.
GAS ASSESSMENT -- shall
mean the assessment on each thousand cubic feet of gas produced from a gas well
to pay the costs incident to the administration of the rules of the
Commission.
GAS REPRESSURING -- shall
mean 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.
GAS-SOUR -- shall mean gas
which contains hydrogen sulfide in sufficient quantities to render it unfit for
domestic or commercial use.
GAS-WELL -- shall mean (1)
a well which produces natural gas only; (2) 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; or (3) any well classed as a gas well
by the Commission for any reason; (4) a well that contains no liquid
hydrocarbons in the reservoir.
GAS-LIFT -- shall mean a
method of injecting gas for lifting a liquid from the well to the
surface.
GAS-OIL RATIO -- shall mean
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 (42 gallons) of
oil, the unit of time being a day of 24 hours.
ILLEGAL OIL -- shall mean
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 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."
ILLEGAL GAS -- shall mean
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 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."
ILLEGAL PRODUCT -- shall
mean 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.
INDICES OF PRODUCTIVE VALUE --
shall mean 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. These indices can mean, at the discretion of
the Commission, acreage, gas oil ratios, static reservoir pressures, flowing
pressures, fluid level drawdowns, the well or wells, or any other pertinent
factors.
LEASE TANK -- shall mean
the tank or other receptacle into which oil is produced either directly from a
well or from a well through gas separator, gun barrel or similar
equipment.
METER -- shall mean an
instrument for measuring and recording the volume of gases or liquids.
MONTH and CALENDAR MONTH --
shall mean the period or interval of time from 7 a.m. on the first day
of any month of the calendar to 7 a.m., of the first day of the next succeeding
month of the calendar.
MUD-LADEN FLUID -- shall
mean any approved mixture of water and clay or other material as the term is
commonly used in the industry.
NATURAL GASOLINE -- shall
mean gasoline manufactured from casinghead gas or from any natural gas.
OIL -- shall mean crude oil
or petroleum.
OIL ALLOWABLE -- shall mean
the amount of oil authorized to be produced by the order of the
Commission.
OIL ASSESSMENT -- shall
mean 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
Commission.
OIL-PIPELINE -- shall mean
oil free from water and basic sediment to the degree that it is acceptable for
pipe line transportation and refinery use.
OIL-WELL -- shall mean any
well capable of producing oil in paying quantities not a gas well.
OPERATOR -- shall mean any
person who, duly authorized, is in charge of the development of a lease or the
operation of a producing well.
OVERAGE, OVER-PRODUCTION --
shall mean the oil or gas produced in excess of the allowable as set by
the Commission.
OWNER -- shall mean the
person who was the right to drill into and produce from any field or reservoir,
and to appropriate the production either for himself or for himself and
another.
PERIOD, ALLOWABLE -- shall
mean the month or day, as designated, in which allowable may be
produced.
PERMEABILITY -- shall mean
a measure, determined by scientific means, of the ability of fluid or gas to
traverse the producing horizon in an oil or gas reservoir.
PERSON -- shall mean any
natural person, corporation, association, partnership, receiver, trustee,
guardian, executor, administrator, Federal agency, or representative of any
kind.
PETROLEUM -- shall mean the
natural untreated oil obtained from an oil well.
PIPE LINE -- shall mean any
pipes above or below the ground used or to be used for the transportation of
oil or gas.
PIPE LINE OIL -- see, Oil,
Pipeline.
PLUG -- shall mean the
abandoning of a producing or non-productive well; the stopping of the flow of
water, gas or oil in a well.
POOL -- shall mean an
underground reservoir containing a common accumulation of crude petroleum oil
or natural gas or both. 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.
POROSITY -- shall mean the
state or quality of being porous; the volume of pore space expressed as a
percentage of the total volume of the rock mass; the percentage or pores of
interspaces forming the total bulk of the material.
POTENTIAL -- shall mean 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 Commission.
PRESSURE BASE -- shall mean
an absolute pressure agreed upon or set as a base for converting the volume of
gas metered to correct volume. The standard pressure base shall be 14.65 pounds
per square inch absolute.
PRESSURE MAINTENANCE --
(1) shall mean the 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.
(2) The introduction of gas or fluid for the
same purpose but obtained from an outside source.
PRODUCER -- shall mean any
person who owns, in whole or in part, a well capable of producing oil or gas or
both in paying quantities.
PRODUCT -- means any
commodity made from oil or gas, and shall include refined crude oil, crude
tops, topped crude, processed crude petroleum, residue from crude petroleum,
cracking stock, uncracked fuel oil, fuel oil, treated crude oil, residuum, gas
oil, casinghead gasoline, natural gas, gasoline, naphtha, distillate, gasoline,
kerosene, benzine, wash oil, waste oil, blended gasoline, lubricating oil,
blends or mixture of oil with one or more liquid products or by-products
derived from oil or gas, whether herein above enumerated or not.
PRODUCTION, ILLEGAL, -- see
Illegal Gas, Illegal Oil.
PRODUCTION INTERESTS --
shall mean the right to a specified part of production.
PROVEN OIL OR GAS LAND --
shall mean 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.
PURCHASER -- shall mean any
person who directly or indirectly purchases, transports, takes or otherwise
removes production to his account from a well or lease. Purchaser is usually
considered to be the person holding the Division Order.
RATABLE TAKE -- see
Controlled Production.
RECOMPLETION -- shall mean
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.
REFINER -- shall mean 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 passing oil through separators to remove gas,
placing oil in settling tanks to remove basic sediment and water, dehydrating
oil, and generally cleaning and purifying oil.
REPRESSURE -- shall mean to
increase the reservoir pressure by the introduction of gas or fluid into the
reservoir.
RESERVOIR PRESSURE -- see
Bottom Hole Pressure.
ROCK PRESSURE -- shall mean
the well head pressure on a gas well that has been closed long enough to attain
a maximum.
ROTARY DRILLING -- shall
mean the hydraulic process of drilling, consisting of rotating a column of
drill pipe to the bottom of which is attached a rotary drilling bit.
RUN -- shall mean oil or
gas removed from the lease.
SEPARATOR -- shall mean an
apparatus for separating gas from oil with relative efficiency, as it is
produced.
SHUT-IN PRESSURE -- shall
mean the pressure noted at the wellhead when the well is completely shut in.
Not to be confused with Bottom Hole Pressure
SPUDDING -- shall mean the
initial step in drilling.
STORER -- shall mean 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
tank or other receptacle under control of said storer, but excluding the
ordinary lease stock of producers.
TAKER -- see
Purchaser.
TENDER -- shall mean a
permit or certificate of clearance for the transportation of oil, gas, or
products, approved and issued or registered under the authority of the
Commission.
TENDERSHIP -- shall mean
the production delivered from one person to another.
TOPPING PLANT -- shall mean
a refinery designed to remove only the gasoline and kerosene fractions from
oil.
TRAP PRESSURE -- shall mean
pressure held at the oil and gas separator.
TRANSPORTER-- shall mean
and include any common carrier by pipe line, barge, boat or other water
conveyance, or truck or other conveyance except railroads, and any person
transporting oil by pipeline, barge, boat or other water conveyance, or truck
and other conveyance.
TUBING -- shall mean the
conduit through which oil or gas is removed from a well.
VACUUM -- shall mean
pressure which is reduced below the pressure of the atmosphere.
VOLATILE -- shall mean
easily wasting away by evaporation.
WASTE -- in addition to its
ordinary meaning, shall mean "physical waste" as that term is generally
understood in the oil and gas industry. It shall include:
(1) 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.
(2) 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.
(3) Abuse of the correlative rights and
opportunities of each owner of oil and gas in a common reservoir due to
non-uniform, disproportionate, and unratable withdrawals causing undue drainage
between tracts of land.
(4)
Producing oil or gas in such manner as to cause unnecessary water channeling or
coning.
(5) The operation of any
oil well or wells with an inefficient gas-oil ratio.
(6) The drowning with water of any stratum or
part thereof capable of producing oil or gas.
(7) Underground waste however caused and
whether or not defined.
(8) The
creation of unnecessary fire hazards.
(9) 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.
(10) The use of gas for the manufacture of
carbon black.
(11) Permitting gas
produced from a gas well to escape into the air.
WATER CONE -- shall mean
the creation of irregularly intruding water by allowing a well to produce too
rapidly.
WELL LOG -- shall mean an
electrical, or any other type of survey, made for the purpose of ascertaining
the strata through which a well bore has penetrated.
WILDCAT WELL -- shall mean
a well drilled outside the geological confines of proven production.
WORKOVER -- shall mean work
of a remedial nature performed within the vertical confines of the same source
of supply.
(Source: 1992 rule book)
RULE A-5:
ENFORCEMENT
PROCEDURES
a) Definitions:
1) "Commission" shall mean the Arkansas Oil
and Gas Commission, on which the Director serves as secretary, but is a
non-voting member.
2) "Director"
shall mean the Commission Director of Production and Conservation.
3) "Regulated Entity" shall mean all
operators, owners, producers or persons subject to Commission regulatory
authority.
4) "UIC" shall mean the
Underground Injection Control program of the Federal Safe Drinking Water
Act.
b) Any regulated
entity engaged in the drilling, operation or plugging of any production,
injection, or other well or drill hole regulated by the 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 rule for violation of any oil, gas and/or brine
statutes, or any rule or permit condition of the Commission.
c) In accordance with Ark. Code Ann. §
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 Non-Compliance
1) A Notice of Non-Compliance may be issued
when any regulated entity is in non-compliance with any requirement of the
Arkansas oil, gas and/or brine statutes, or rules, orders, or any permit
condition, and:
A) That the non-compliance was
not caused by the regulated entity's deliberate action;
B) That any action necessary to abate the
non-compliance was commenced immediately and was or will be completed within a
specified date certain, as established by the Director, 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 non-compliance; and
C) That the non-compliance has not caused and
cannot reasonably be expected to cause significant environmental harm or damage
to property.
2) The
notice of non-compliance 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 AOGC Form 1 Organization Report. The written
notification shall indicate the nature and circumstances of the non-compliance,
and the time within which and the means by which the non-compliance 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
subparagraph (e) below.
4) The
provisions of this subparagraph (d), shall not apply to the following types of
incidents, which may require a Notice of Violation to be issued in accordance
with subparagraph (e) below:
A) Conducting
any regulated activity specified in paragraph (b) above prior to issuance or
re-issuance of the appropriate Commission permit or authority;
B) Operating an annular or casing
injection/disposal well or a well with pressure on the annulus;
C) Failure to maintain required performance
bond or pay annual well fees;
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(s)
1) 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 oil, gas, and/or brine statutes, or rules,
orders, or any permit conditions of the Commission. 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, or 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;
C) The time within
which the violation should be abated; and
D) A notice of any civil penalties, as
specified in subparagraph g) below, the Director will request to be issued by
the Commission.
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 CFR 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, or 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 General Rule B-2;
B) Failure to pay annual well fees as
specified in General Rule B-2;
C)
Failure to pay any monies due the Abandoned and Orphaned Well Plugging Fund as
specified in General Rule G-1; or
D) Failure to comply with the provisions of
General Rule B-42, or General Rule E-3.
E) Any other violation for which a state-wide
cessation requirement is authorized by an oil, gas and/or brine statute, or
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 AOGC Form 1
Organization Report, charged with the violation(s), or provide personal
delivery of a copy of the notice to the regulated entity, or the regulated
entity's representative.
6) The
regulated entity charged with the violation(s) may request a Director's Review
of the Notice of Violation and provide the Director, in writing, any
information in mitigation of the violation(s) 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. Such written information may include a proposed
alternative to the required action needed to abate the violation(s). Upon
receipt of such information from the regulated entity, the Director, shall
conduct a review.
7) During the
review, the Director may consider any of the following criteria in reaching a
Final Director's Decision regarding the violation(s):
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;
C) The degree of
culpability of the regulated entity; and
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; or
B) vacate the violation; or
C) amend or modify the type of violation and
abatement requirements specified in the violation; or
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.
9) The Final
Director's Decision shall be delivered to the regulated entity, or the
regulated entity's representative, as reported on the AOGC Form 1 Organization
Report, via first class mail. The Final Director's Decision may be appealed to
the Commission by filing an application in accordance with General Rule A-2,
A-3, and other applicable hearing procedures. 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. The
application shall state the reason for the appeal and shall be scheduled to be
heard by the Commission in accordance with General Rule A-2, A-3, 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) All violations
specified in a Notice of Violation(s) which have become a final administrative
decision in accordance with subparagraph e) 10), a Final Director's Decision
which has become a final administrative decision of the Commission in
accordance with subparagraph e) 11), or by 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. 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 subparagraph e) 10), a Final
Director's Decision which has become a final administrative decision of the
Commission in accordance with subparagraph e) 11), or by Order of the
Commission have been fully abated.
f) In addition to the issuance of a Notice of
Violation(s), the Director may initiate further enforcement proceedings, as
provided for in statute, as follows:
1)
Assessment of a civil penalty as provided in Ark. Code Ann. §
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 Ark. Code Ann. §
15-71-110(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 Ark. Code Ann. §
15-72-108
or §
15-76-304;
4) The filing of a criminal complaint in any
court of competent jurisdiction, as provided for in Ark. Code Ann. §
15-71-114,
§
15-72-104
or §
15-76-303.
g) Civil Penalties
1) 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 subparagraphs (g)
(2) and (3) below. The Director shall determine whether to request the
assessment of civil penalties for violations issued under subparagraphs (g) (4)
and (5) below. 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 designee may file
an application, in accordance with General Rule A-2, A-3, and other applicable
hearing procedures, to request the issuance of the requested civil penalty by
the Commission. The maximum amount of the Director's requested civil penalty
shall be computed as provided in subparagraphs (g) (2) through (5) below.
However, the Commission is not bound by the Director's request, or the amounts
provided below, and may impose civil penalties of up to the maximum amounts
permitted by law.
2) Administrative
violations, 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 file production and well
reports or other reports required by Commission rules, orders or permit
conditions; failure to notify the Commission before the setting of surface
casing, or the plugging of a well; failure to maintain required performance
bond in force for the wells under permit; or pay annual well fees within the
specified time. The Director may request the assessment of up to $1000 per
administrative violation and up to $1000 per day for each day the violation
remains unabated after the specified compliance date. The per administrative
violation civil penalty request shall be calculated as follows:
A) No previous violation of the same rule:
$250. One previous violations of the same rule: $500. Two or more previous
violations of the same rule: $1000. The fourth and each subsequent violation of
the same rule shall be considered a significant violation in accordance with
subparagraph g) 4) below.
B) The
time frame used for determining previous violations shall be limited to the
regulated entity's violation record for the preceding three full calendar years
before the issuance of the violation.
3) Operating violations, defined as failure
to maintain compliance with Commission rules on well drilling and operation,
and production facility, pipeline and seismic operations and/or commencing
operations requiring a permit prior to issuance or re-issuance of the required
permit or authority. These operations include, but are not limited to regulated
activities such as, operating a well or natural gas pipeline system without the
proper permit or transfer of ownership, failure to maintain a well or crude oil
flow line in a leak-free condition, failure to comply with non-jurisdictional
natural gas pipeline requirements, failure to notify of a spill occurrence,
failure to maintain containment dikes, or operating an Exploration and
Production Fluid Transportation System without a proper permit. Multiple
incidents of the same violation against a regulated entity on the same occasion
shall not be considered separate violations. The Director may request the
assessment of up to $2500 per operating violation and up to $2500 per day for
each day the violation remains unabated after the specified compliance date,
with the exception that operating violations as specified in Ark. Code Ann.
§
15-76-303
are limited to a maximum of $1,000 per operating violation. The per operating
violation civil penalty shall be calculated as follows:
A) No previous violation of the same rule
$500. One previous violation of the same rule, $750; two or more previous
violations of the same rule, $1000. The fourth and each subsequent violation of
the same rule shall be considered a significant violation in accordance with
subparagraph g) 4) below.
B) The
time frame used for determining previous violations shall be limited to the
regulated entity's violation record for the preceding three full calendar years
before the issuance of the violation; plus
C) If the violation 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
$250; or, if the violation 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 $500; or, if the violation
caused environmental impact to soil and/or land surface, vegetation or crops,
surface water, groundwater, livestock or wildlife, add $1000, or
D) 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 $2000.
4) Except as limited in Ark. Code Ann. §
15-76-303,
or as otherwise provided in subparagraphs g) 5) or 6) below, significant
violations may result in a request by the Director or his or her designee, of a
civil penalty of up to $2500 per violation and up to $2500 per day for each day
of the violation for the following types of violations: failure to comply with
the provisions of General Rule A-7, failure to comply with well spacing
provisions, operating a UIC well without a proper permit, operating an annular
or casing injection/disposal well, operating a UIC well prior to establishing
mechanical integrity, operating a UIC well with a failed mechanical integrity
test, operating a UIC well with pressure on the annulus, failure to provide
emergency response or remediate a crude oil or produced water spill, or the
improper disposal or discharge of produced fluids. The per violation civil
penalty shall be computed as follows:
A) An
initial amount of $1000; plus
B)
One or more previous violations of the same type: add $500 per violation;
plus
C) If the violation caused
environmental impact to surface water, ground water or wildlife: add $1000, or
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
$1500.
D) The time frame used for
determining previous violations shall be limited to the regulated entity's
violation record for the preceding three full calendar years before the
issuance of the violation.
5) In accordance with Ark. Code Ann. §
15-72-103, the
Director, or his or her designee, may request a civil penalty of up to $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) All civil penalties assessed
and paid to the Commission shall be deposited in the Commission operating fund.
Additionally, all civil penalties assessed and paid, for violations specified
in Ark. Code Ann. §
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.
(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)
RULE
A-6:
RESERVED
Reserved for Future Use
RULE A-7: DETERMINATION OF
NATURAL GAS WELL CATEGORIES FOR SEVERANCE TAX PURPOSES
a) Applicability
In accordance with Ark. Code Ann. §
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 Arkansas Department of
Finance and Administration to determine the appropriate severance tax rate for
each well. All gas production wells under the jurisdiction of the Oil and Gas
Commission are subject to the provisions of this rule.
b) Definitions:
1) "Commission" shall mean the Arkansas Oil
and Gas Commission, on which the Director serves as secretary, but is a
non-voting 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 the Fayetteville Shale, Woodford Shale,
Moorefield Shale and the Chattanooga Shale, or their stratigraphic equivalents
as described in published stratigraphic nomenclature recognized by the Arkansas
Geologic Survey; or
B) Produces gas
from any completion that is located at a depth of more than 12,500 feet 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; or
C) Produces gas from a tight gas formation
which is defined as a formation which:
i) Has
previously been determined to be a low permeability formation by Commission
Orders or field rules for Booneville and Chismville ( 84-2003-07 ), Gragg (
89-2004-07 ), Waveland ( 86-2004-07 ), Rich Mountain ( 304-2006-09 ), Mansfield
( 28-2003-03 ), Witcherville and Excelsior ( 103-2005-07 ); and General Rule
B-44; or
ii) Is determined by the
Director 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 Commission and issued by the Director.
D) Produces gas from a geopressured brine;
or
E) Produces occluded gas from a
coal seam.
5) "Marginal
Conventional Gas Well" shall mean a conventional gas well which is incapable of
producing more than 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 of the current wellhead deliverability rate methodologies described
in subparagraph h) below.
6)
"Marginal High Cost Gas Well" shall mean a high cost gas well which is
incapable of producing more than 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 of the current wellhead deliverability rate methodologies
described in subparagraph h) below.
7) "New Discovery Gas Well" shall mean any
conventional gas well for the period commencing on the date of first production
and ending on the date that is 24 consecutive calendar months following the
date of first production.
c) On or before January 1, 2009, the Director
shall determine the initial well category for each existing gas producing well
in the State. If a well contains two or more separately metered producing zones
(sources of supply), and one 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 General Rule D-16. On or before
January 1, 2009 the Director shall notify each permit holder of each existing
wells determination as a:
1) 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 36 consecutive calendar months
following the date of first production, unless a longer time period is granted
by the Department of Finance and Administration in accordance with Ark Code
Ann. §
26-58-127;
or
2) Marginal Conventional Gas
Well; or
3) Marginal High Cost Gas
Well; or
4) New Discovery Gas Well;
or
5) A Conventional Gas
Well.
d) After January
1, 2009 the Director shall determine, at the time of permitting each new well,
the appropriate well category as specified in subparagraph c) above, which
shall be effective the date of first production from the well. This well
category determination, made at the time of the initial new well permit
issuance or as amended in accordance with this subparagraph or subparagraph g)
below, shall determine the well category throughout the life of that well. Once
a permit is issued, if a well is completed in two or more separately metered
producing zones (sources of supply), and one 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 General Rule D-16. 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 Marginal Conventional Gas Well or a
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, another well category determination with respect to the well category
definitions specified in subparagraph b) above, in accordance with the
application procedures specified in subparagraph i) below.
f) Upon submission of the application and
supporting documentation or other required information, the Director shall make
a determination within fifteen (15) calendar days from the receipt of such
application.
1) The effective date of the well
category determination request shall automatically be the first day of the next
month following the postmark date the application was mailed to the Director or
date of the Director's Office date stamp, if delivered in person to the
Director.
2) If approved by the
Director, the application shall be sent via first class mail to the permit
holder and a copy forwarded to the Department of Finance and Administration
("DFA").
3) If the application is
denied by the Director, the permit holder may appeal the Director's
determination to the Commission by filing an application in accordance with
General Rule A-2, A-3, and other applicable hearing procedures. If the permit
holder does not appeal the denial, and the date of the Director's denial occurs
after the effective date of the well determination request as defined in
subparagraph f) 1) above, the permit holder may be subject to additional
payment provisions in accordance with DFA procedures. 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) If following a review of completion
reports, monthly production reports, the applicable wellhead deliverability
rate, utilizing one of the current methodologies specified in subparagraph h)
below, or other information, the Director determines a well is not correctly
categorized, the Director shall determine the correct well category and notify
the permit holder. The corrected well category determination shall become
effective on the first day of the month following the month in which the
Director notifies the permit holder of the corrected well category
determination, unless the permit holder files an appeal of the Director's
decision in accordance with General Rule A-2, A3, and other applicable hearing
procedures.
h) All existing well
category determinations under subparagraph c) and all new well category
determinations under subparagraph d) shall be made on the basis of one of the
following current wellhead deliverability rate methodologies:
1) Establishing cumulative deliverability of
the well utilizing test methodologies specified in General Rule D-16;
or
2) 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. 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) 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 subparagraph b) 4) above. 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 36 consecutive calendar months following the date of
first production, unless a longer time period is granted by the Department of
Finance and Administration in accordance with Ark Code Ann. §
26-58-127.
B) 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 subparagraph b) 4)
above at the time of well categorization in accordance with subparagraphs d)
and g) above. The well shall automatically qualify for a cost recovery period
for a period of 36 consecutive calendar months following the date of first
production, unless a longer time period is granted by the Department of Finance
and Administration in accordance with Ark Code Ann. §
26-58-127.
C) At the conclusion of the cost recovery
period, specified in subparagraph i) 1) A) and B) above, the well shall
automatically be re-classified as a High Cost Gas Well no longer subject to the
tax rate for the cost recovery period, and shall be subject to the applicable
severance tax rate specified in Ark Code Ann. §
26-58-111(5)(D)
unless an application is made for classification as a Marginal High Cost Gas
Well in accordance with subparagraph i) 3) B) below. The effective date of the
automatic re-classification 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) 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 subparagraphs d) and g) above. The well category determination
shall remain in effect for 24 consecutive calendar months following the date of
first production.
C) At the
conclusion of the 24 consecutive calendar months following the date of first
production, the New Discovery Gas Well determination shall automatically
terminate. 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. The well shall be automatically re-classified as a Conventional Gas
Well subject to the applicable severance tax rate specified in Ark Code Ann.
§
26-58-111(5)(D),
unless application is made for classification as a Marginal Conventional Gas
Well in accordance with subparagraph i) 3) B) 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 New Discovery Gas Well during the cost
recovery period set forth in subparagraphs i) 2) A), and B) above, or a High
Cost Gas Well during the cost recovery period set forth in subparagraphs i) 1)
A) and B) above.
B) 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, for a Marginal Conventional Gas Well or Marginal High
Cost Gas Well category determination. The request shall be on a form prescribed
by the Director and shall include a copy of the most recent well head
deliverability rate determination for all producing zones based on one of the
current wellhead deliverability rate methodologies specified in subparagraph h)
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 subparagraph f) above.
D) A permit holder shall immediately notify
the Director 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. When a previously determined Marginal Conventional Gas Well
becomes capable of producing more than 250 Mcf per day over a 30 day period or
a well previously determined to be a Marginal High Cost Gas Well becomes
capable of producing more than 100 Mcf per day over a 30 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 of the current wellhead
deliverability rate methodologies specified in subparagraph h) above, along
with the required written notice to the Director.
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 Ark Code
Ann. §
26-58-111(5)(D).
j) Failure to comply with any
provision of this rule may result in the initiation of enforcement actions in
accordance with General Rule A-5, including the assessment of a civil penalty
not to exceed two thousand five hundred dollars ($2500) per day for each day of
the violation.
(Source: new rule November 16, 2008; amended June 5, 2009)
RULE A-8:
REPEALED
Rule Repealed Effective July 1, 2016
GENERAL RULE B - DRILLING AND
PRODUCTION
RULE
B-1:
APPLICATION TO DRILL A PRODUCTION
WELL
a) Definitions:
1) "Production Well" means a well drilled,
deepened, or re-entered after plugging, for the exploration or production of
oil and/or gas or brine; or a well drilled, deepened or re-entered after
plugging for a water supply for use in connection with an enhanced oil recovery
project.
2) "Deepen" for a cased
well means an operation whereby a well is drilled to a measured depth below the
cement casing shoe. 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) "Permit Holder" means the person to whom
the permit is issued and is responsible for all regulatory requirements
relative to the production well.
5)
"Re-enter" means an operation whereby access to a previously plugged wellbore
is reestablished for any purpose including replugging.
6) "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
Arkansas General Rule B-43(c) or (d). "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. For purposes of this rule, "Shale Operations" does
include well site construction operations.
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 Re-enter a Production Well
1) No person shall drill, deepen, or re-enter
a plugged production well, without a permit. A copy of the permit shall be
posted on site prior to a well being spud or the commencement of deepening or
re-entering operations.
2) The
Permit Holder is required to provide notice to the surface owner in accordance
with Ark Code Ann. §
15-72-203.
A) If notice is required in accordance with
Ark Code Ann §
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:
A) the proposed date Shale Operations will
commence; and
B) the location of
the proposed well and the pad location, including the section, township, range,
and plat of the pad location, if available; and
C) a statement that the Permit Holder has a
pending or approved drilling permit for the proposed Shale Operations on the
surface owner's property and that the permit shall be available for inspection
by the surface owner on request by the surface owner; and
D) the name, address, telephone number, fax
number, and electronic mailing address of the Permit Holder or the Permit
Holder's agent.
B) The
Notice shall be sent by certified United States mail 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.
C) 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.
D) Written notice under this subsection is:
i) presumed delivered three (3) days after
mailing by certified mail;
ii)
effective immediately upon hand delivery;
E) 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.
F) 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.
G) The provisions of
subparagraphs b) 2) A) through F) above do not supersede, modify, or supplant
the notice provisions of General Rule B-42.
3) The Permit Holder shall notify the
appropriate 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 re-entering operations. Commission staff may
conduct site inspections as deemed necessary.
4) 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. The Director may
approve the commencement of drilling operations prior to the filing of an
amended permit. 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.
Drilling may not commence prior to the issuance of a new permit.
5) Application for a permit to drill, deepen
or re-enter a plugged production well shall be made on forms prescribed by the
Director. The application shall be executed under penalties of perjury,
accompanied by a non-refundable permit fee of $300.00; and the permit shall not
be issued until any required financial assurance in accordance with General
Rule B-2 is submitted and approved.
6) If the application does not contain all of
the required information or required documents, the Director, or his designee,
shall notify the applicant in writing. The notification shall specify the
additional information or documents necessary for an evaluation of the
application, and shall 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 re-entry of plugged production well
operations authorized by the permit has occurred, which are to be continued
with due diligence, but not to exceed 1 year from the date of commencement of
the drilling, deepening or re-entry 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) Permits for the drilling,
deepening or re-entry of plugged production well are not transferable prior to
the completion of drilling operations and the setting of surface casing. A new
permit application, along with a new permit fee and plat must be
filed.
9) The permit application to
drill, deepen or re-enter a plugged production well shall include at a minimum:
A) The proposed name of the production
well.
B) The surveyed location and
ground elevation of the production well. A survey is not required for a
deepened production well, or a re-entered plugged production well, if the
original production well location was surveyed and shown on the original
production well permit application. 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. 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 General Rule B-43 or B-44, or a Form 5 must be submitted for a location
exception in accordance with General Rule B-40.
C) A plat showing:
i) The exact location of the production well
proposed to be drilled,deepened or re-entered; an outline of the proposed
drilling unit and/or leasehold, whichever is applicable, unless the production
well is a wildcat well; and the distance from the production well to the
nearest section lines, drilling unit lines and or lease lines, whichever is
applicable; and
ii) 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 the name of the deepest geologic formation to be
tested.
10) The
application for a permit to drill, deepen or re-enter 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 General Rule B-13.
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
Rule, 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;
B) No further permits
or authorities may be issued in accordance with General Rule A-5.
c) Production Well
Drilling Permit Revocation Procedures
1) The
Director may revoke a production well drilling permit if the Permit Holder
fails to meet permit conditions as specified in the production well drilling
permit, the production well permit was issued in error, or the Permit Holder
falsified or otherwise misstated any material information in the application
form.
2) The Director shall notify
the Permit Holder of the production well drilling permit in writing. Following
the revocation notice the Permit Holder is required to plug the production
well. 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 General Rule A-2, A-3, and
other applicable hearing procedures. Drilling or production may not commence or
continue during the appeal process. 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.
(Source: 1992 rule book; amended July 29, 2011; amended January
20, 2014)
RULE B-2:
PROOF OF FINANCIAL RESPONSIBILITY REQUIRED TO BE
FURNISHED
a. For purposes
of this rule, the person, operator, producer, or owner designated by the
Director of Production and Conservation or his 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 an 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(s) or
well(s); 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(s) or well(s) to
another permit holder.
c. Financial Assurance is required to remain
in full force and effect by the designated permit holder:
1. for one year after the issuance of the
permit to drill in accordance with A.C.A.
15-72-214;
or
2. until the well(s) have been
plugged and associated production site(s) restored in accordance with
Commission rules; or
3. the well(s)
have been transferred to a new permit holder in accordance with Commission
rules; or
4. all outstanding
notices of violation or orders of compliance issued against the permit holder
have been satisfied; or
5. the
permit holder has paid annual fee assessments to the Commission in accordance
with section h. of this rule for two consecutive years, and such permit holder
is not in violation of the Commission's rules or statutes; or
6. all permit holders of record with the
Commission on January 1, 2006 who were assessed annual fees in accordance with
section (h) of this rule and paid such fees, and who were not in violation of
any Commission order or rule at the time the fees were paid.
d. 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.
B.
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. 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
enforceable in the Courts of Arkansas, and shall be construed under Arkansas
law.
3. A Certificate of
Deposit subject to the following conditions:
A. The Director of Production and
Conservation or his 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. If assigned, the Director of Production
and Conservation or his designee shall require the banks issuing these
certificates to waive the rights of setoff or liens against those
certificates.
B. The Director of
Production and Conservation or his 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.
D. The Certificate of deposit, if a
negotiable instrument, shall be placed in the Commission's possession. 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 cashiers
check to be deposited in the Commission's authorized bank account.
e. Financial Assurance shall be
required for:
1. all holders of permits to
drill and/or operate gas well(s), and all Class II disposal wells injecting
fluids associated with dry gas production wells; and
2. all permit holders of commercial Class II
disposal wells; and
3. all permit
holders of brine production and Class V brine disposal well(s), and
4. all permit holders of other types of wells
or exploratory holes or wells, and
5. all permit holders of liquid hydrocarbons
production wells and Class II disposal and enhanced oil recovery injection
wells operated in conjunction with liquid hydrocarbon wells, whom have not been
a permit holder of record with the Commission for a minimum of two calendar
years preceding the date of the application specified in section (b)
above.
f. When a permit
holder is required to submit Financial Assurance, the minimum amount of the
Financial Assurance shall be:
1. $3,000 per
well for an oil and /or gas production well, Class II Enhanced Recovery well;
brine production well, water supply well, or other type of exploratory hole or
well; or
2. $25,000 for a Class II
Disposal or Class V Brine Disposal wells; or
3. $50,000 for a Class II Commercial Disposal
well; or
4. A blanket financial
assurance as follows:
A. $25,000 for 1-25
wells; or
B. $50,000 for 26-100
wells; or
C. $100,000 for 101 or
more wells.
g. The Director of Production and
Conservation or his designee is authorized to approve administratively each
financial assurance instrument required to be filed with the Commission. The
Director is further authorized to require additional financial assurance based
on but not limited to how long a permit holder has operated in the State,
environmental consideration of the well location, and other factors impacting
the cost of plugging the well and restoring the associated well site, and 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.
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. Liability for payment of annual well fees ceases on the date
when the well has been plugged and restored, or on the effective date stated on
the Commission's Notification of Transfer form.
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 cashiers check or money
order.
i. A permit
holder may administratively contest the amount of the fee assessment as
follows:
1. By submitting a written objection
to the assessment amount on or before March 1 of each year. The objection must
be accompanied by the full assessed amount.
2. The objection must be in writing, signed
by the permit holder, or by an individual authorized to sign for the permit
holder, and must identify the nature of the objection. The written objection
must include a statement of the facts supporting the objection and copies of
any relevant documents to support the objection.
3. The Director of Production and
Conservation or his designee shall review the application, and has 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. 1-5 Permits or Wells
|
$100/Well
|
2. 6-15 Permits or Wells
|
$750/Operator
|
3. 16-50 Permits or Wells
|
$1,250/Operator
|
4. 51-150 Permits or Wells
|
$2,000/Operator
|
5. 151-300 Permits or Wells
|
$3,000/Operator
|
6. 301 or more Permits or Wells
|
$4,000/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. 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. No financial
assurance liability shall be released until the successful completion of all
plugging, replugging, repair or site restoration ordered by the
Commission.
3. In the event
forfeiture of the financial assurance is warranted under the provisions of this
rule, 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 subsection
(1). If the permit holder does not request a hearing within the fifteen (15)
day period, the Director shall issue a final decision ordering forfeiture and
collection of funds. If a hearing is requested by the permit holder, the
hearing shall be docketed for the next regularly scheduled Commission
hearing.
4. At the forfeiture
hearing, the Director shall present evidence in support of the determination
for financial assurance forfeiture. The Permit Holder shall present evidence
contesting the Director's determination. 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 findings of
fact, conclusions of law and the disposition of the case.
(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)
RULE B-3:
SPACING OF WELLS
a. For purposes of this rule 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) 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. For purposes of
assigning an API number the well site location shall be considered the actual
surface location of the well.
(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. In a vertically drilled well without a
directional survey, the well location is the surface location. 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;
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 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 280 feet from the drilling unit
boundary, except that wells drilled in exploratory drilling units established
by General Rule B-43 or General Rule B-44, shall be governed by the applicable
well setback provisions of General Rule B-43 or General Rule B-44,
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, General Rule B-43, or General Rule B-44shall not be located closer
than 280 feet from a quarter, quarter division line within a governmental
section.
(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 set
back provisions specified in e (1) above.
f. The well location for a well drilled for
oil or gas production purposes, and completed in pools in field(s) where Field
Rules do not exist for these uncontrolled pools, shall not be located closer
than 280 feet 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 General Rule H-1):
(1) The well location for an injection well
drilled or completed for enhanced recovery purposes shall not be located closer
than 280 feet 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
General Rule H-1 shall be located no closer than 280 feet 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
General Rule H-1, outside of a controlled field and not within an uncontrolled
field, shall be located no closer than 280 feet from a quarter, quarter
division line within a governmental section.
(4) The well location for a Class II Disposal
Well, or Class II Commercial Disposal Well, within an uncontrolled field,
drilled or completed pursuant to General Rule H-1 shall be located no closer
than 280 feet from the mineral lease line. However, with regards to Class II
Disposal Wells, this requirement may be waived by the Director if the offset
operator(s) 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 AOGC Regional Office.
h. 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 rule with the exception of the set back
provisions for well location. No production of hydrocarbons will be allowed
from a water supply well.
i. The
Commission may, after notice and hearing, grant exceptions to the rule,
provided such exceptions will create neither waste nor hazards conducive to
waste. No well drilled in violation of this rule 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 such rule shall be plugged.
(Source: 1992 rule book; amended November 13, 2005; amended
September 16, 2006; amended November 19, 2018)
RULE B-4:
APPLICATION TO
TRANSFER A WELL
a)
Definitions
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 right to drill, produce and/or operate said well(s),
possesses the full rights and responsibilities for operating the well(s) in
accordance with applicable Arkansas law and/or rule or order of the Commission,
and has the current obligation to plug said well(s), who is the assignor,
transferor or seller (whether voluntary or involuntary) of the
well(s).
2) "Deepen" for a cased
well means an operation whereby a well is drilled to a measured depth below the
cement casing shoe. 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 person acquiring
the well(s) and the right to drill, produce, and/or operate said well(s), who
obtains the full rights and responsibilities for operating the well(s) in
accordance with applicable Arkansas law and/or rule or order of the Commission,
whom will obtain the obligation to plug said well(s), and who as owner or
operator in accordance with applicable Arkansas law and/or rule or order of the
Commission is required to hold the permit.
5) "Re-enter" 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.
7) "Well" means a production well as defined
by General Rule B-1.
b)
The provisions of this rule 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:
1) A change of ownership of the right to
drill, produce and/or operate well(s), including the obligation to ultimately
plug said well(s); or
2) A change
in the designation of the owner or operator under an operating or other similar
agreement; or
3) A change pursuant
to the action of the owners of separate interests who designate an 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 well(s), including the
right to drill, produce and/or operate well(s), and the obligation to
ultimately plug said well(s)
c) The provisions of this rule 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) The provisions of this
rule shall not apply to transfers of well(s) abandoned or orphaned in
accordance General Rule G-1 or G-2. Transfers of well(s) deemed abandoned or
orphaned are subject to the transfer provisions in General Rule G-3.
e) Notification of a transfer shall be given
to the Director, or his 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 General Rule B-13, 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.
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 designee,
approving the transfer request, the New Permit Holder shall:
1) Be authorized to do business within the
State of Arkansas; and
2) Provide
the required financial assurance, if applicable, in accordance with General
Rule B-2 and subparagraphs h) 4) and h) 5) below; and
3) File the required organizational report,
if applicable, in accordance with General Rule B-13; and
4) If the transfer is for a gas well
producing less than 25 MCF/day per AOGC records, or a well that has received an
approved temporarily abandonment status in accordance with General Rule B-7,
then the Current Permit Holder and New Permit Holder shall file an application
in accordance with General Rules A-2, A-3, and other established hearing
procedures to have the Commission review the transfer request.
a. 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 $35,000 for each
natural gas well in a form authorized by General Rule B-2, unless otherwise
provided by the Commission after notice and hearing:
5) If the transfer is for a liquid
hydrocarbon production well has received an approved temporarily abandonment
status in accordance with General Rule B-7, 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 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 h) 4) above; or
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 General Rule A-5 e)
12); or
5) The Director, or his
designee, deems it necessary that the transfer request be denied for the
purpose of protecting correlative rights of all parties, or to prevent waste as
defined by Ark. Code Ann. §
15-72-102.
j) 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
well(s). 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) 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. However, if the New
Permit Holder, after being notified of the violation(s), agrees in writing to
the transfer approval including conditions to abate all violations, the
transfer may be approved by the Director, or his designee in accordance with
this Rule. Failure to abate the violations within the time period specified by
the Director or his designee may result in revocation of the transfer approval
in accordance with subparagraph (o) below, and/or other applicable enforcement
actions in accordance with General Rule A-5.
l) 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. However, if the transfer is
denied by the Director, or his designee, the Current Permit Holder assumes all
responsibility for the violations caused by the New Permit Holder. Nothing in
this subparagraph shall affect the contractual rights and obligations between
the person or entity transferring the well(s) and the person or entity
acquiring the well(s).
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) The Director shall notify the Current and
New Permit Holder of the transfer approval or denial in writing. 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 General Rule A-2, A-3 and
other applicable hearing procedures. 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 Permit Holder fails to meet permit
conditions as specified in the well transfer approval, the well transfer
approval was issued in error, or the Permit Holder falsified or otherwise
misstated any material information in the application form.
2) The Director shall notify the Permit
Holder of the well transfer revocation in writing.
Following the revocation notice the Permit Holder is required to
plug the well. 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 General Rule A-2, A-3 and other
applicable hearing procedures. Drilling, production, or operation may not
commence or continue during the appeal process. 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.
(Rule Repealed Effective November 11, 2007; New Rule Effective
November 19, 2018)
RULE B-5:
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 Commission and
its agents at all reasonable times.
b. For purposes of this rule, original
completion shall be defined as initial zone perforation, and configuration of
wellhead for production, excluding pipeline connections. 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 Section (d)
or (f) below.
c. For purposes of
this rule, recompletion is as defined in General Rule A-4.
d. For purposes of this rule, workover is as
defined in General Rule A-4. Upon completion of workover operations, only well
records specified in Section (f)(1)(3) 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 Section (f) (1), (2) and (3) within 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. 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 logs, to be submitted in a 1 inch, 2 inch and 5 inch to 100 foot
scale format or other scale format acceptable to the Commission. All logs shall
be submitted, at a minimum, as paper copies in standard continuous logging
paper format. 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 (200 DPI
Black & White in TIF, JPG, BMP) to the Commission on an approved electronic
storage device. 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.
5. Application to Abandon other than for a
dry hole
g. For
directional or horizontal wells, or deviated wells not in compliance with
General Rule B-30, the following shall also be submitted:
(1) 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. The plat should provide and present the following:
A. 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; and
B. The distance between common sources of
supply for which an allowable determination is required; and
C. The actual location of the entire
perforated length of the lateral section in a horizontal well showing the set
back distances to offset wells.
(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. The above reports
shall be filed within 30 days of the original completion, recompletion or
workover of the well and prior to commencement of production. Upon receipt of
the required information specified in Section (f) (1), (2) and (4), and Section
(o) (8) of General Rule B-43 if applicable, a Certificate of Compliance shall
be issued granting authority to produce and transport oil and/or gas for a
period of 30 days at which time the required information specified in Section
(f) (3) must be on file in order for a final Permit to Produce and Transport to
be issued. However, if completion activities are not completed within 90 days
of the setting of the production casing or other production related casing, the
required information specified in (f) (1), (2) and (3) 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 rule 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 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 Section (f) (2) be kept
confidential, the request will be honored for a period not to exceed 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.
(Source: 1992 rule book; amended September 16, 2006; amended
January 14, 2008; amended May 11, 2008)
RULE B-6: 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 prevent water from entering any oil or
gas-bearing formations, and to protect any underground or surface water that is
suitable for domestic or irrigation purposes from waste, downward drainage,
harmful infiltration and addition of deleterious substances.
(Source: 1992 rule book)
RULE B-7:
WHEN WELLS SHALL BE PLUGGED AND ABANDONED AND
NOTICE OF INTENTION TO PLUG AND ABANDON WELLS
a) The current permit holder is responsible
for plugging wells as defined in this rule. In the case of leaking wells,
plugging responsibility is in accordance with General Rule B-26 (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 Rule
B-10, 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 commission rules, unless an extension
of time to plug is granted in accordance with subparagraph (c) below.
c) Uncased wells and dry holes
1) 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. 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 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 subparagraph 2) below.
2) The Director however, may grant an
extension of time to plug an uncased well. In determining whether to grant an
extension and in determining the length of an extension, the Director may
consider:
A) The permit holders specific
plans for further wellbore utilization,
B) The total depth of the well,
C) The depth of surface and any intermediate
casing,
D) A description of the
current condition of the hole including a description of the type of drilling
fluids currently in the well,
E)
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) All cased wells utilized for
liquid hydrocarbons, natural gas or brine production, water supply or injection
purposes, except such holes as are described in Rule B-10 or liquid
hydrocarbons 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 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
subparagraph h) below. Upon such determination by the Director or if temporary
abandonment status is denied, the Permit Holder shall commence plugging the
well within 30 days after notification by the Director. Failure to commence
plugging the well within 30 days after notification by the Director may result
in the initiation of well abandonment proceedings in accordance with General
Rule G-1.
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 8 hours, prior to commencement of plugging
operations.
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 72 hours prior
to the commencement of plugging operations.
f) Upon receipt and review of such verbal or
written notice, the Commission Regional Office shall authorize the commencement
of plugging operations and may send a duly authorized Commission representative
to the well location to witness the plugging of such well.
g) Authorization to plug and abandon is not
granted unless the appropriate notice, as specified in subparagraph (e) above,
has been provided to the Oil and Gas Commission by the permit holder or person
responsible for the plugging of the well. 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) An application for
temporary abandonment status shall be made on 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. At the expiration of the three (3)
year period the Permit Holder shall commence plugging operations within thirty
(30) days, or file an application to request a hearing before the Commission in
accordance with General Rules A-2, A-3 and other applicable hearing procedures
to request an extension of the three (3) year period of the temporary
abandonment status. Wells in an approved waterflood/enhanced oil recovery unit
are exempt from the initial three (3) year time limit as long as the unit
remains active.
2) Wells which have
not produced for more 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. Temporary
abandonment status for these wells may only be granted by the Commission after
notice and a hearing in accordance with General Rule A-2, A-3 and other
applicable hearing procedures.
3)
Temporary abandonment status shall be approved by the Director provided:
A) Financial Assurance in the amount of
$35,000 per well for any dry natural gas production well, or $15,000 per well
for any liquid hydrocarbon production well is submitted for each well. The
Financial Assurance shall be in a form as prescribed by General Rule B-2, and
shall remain valid until the well is put back into sustained production,
plugged or transferred, and
B) The
well is secured with a suitable wellhead with no leakage of any substance at
the surface, and
C) The well site
is maintained in accordance with General Rule B-26 i), and
D) Proper well identification is maintained
in accordance with General Rule B-26 b), and
E) Useable groundwaters are protected
utilizing one 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 150 feet below the base of the lowest usable groundwater in the area, and
secured at the surface with a wellhead and valve in operable condition;
or
ii) Set a packer run on tubing
above the producing interval, in the cemented portion of the production casing,
but at least 150 feet 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) Conduct a fluid level test by wireline or
other approved electronic or mechanical means, which determines that the static
fluid level is at least 150 feet below the base of the lowest usable
groundwater in the area, and upon no less than 48 hours notice prior to
conducting the fluid level test, which may be witnessed by commission staff.
The fluid level test shall be conducted annually, within 60 days prior to the
anniversary date of the temporary abandonment during each year of the three (3)
year temporary abandonment period.
4) Failure to maintain any of the above
conditions may result in the issuance of a Notice of Violation ("NOV"). Failure
of the Permit Holder to comply with the NOV, or other applicable final
administrative decision in accordance with General Rule A-5, shall result in
the revocation of the temporary abandonment status and 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.
(Source: 1992 rule book; amended December 16, 2007; amended
February 19, 2009; amended November 19, 2018)
RULE B-8:
PLUGGING METHODS AND
PROCEDURES
The methods and procedures for plugging a well shall be as
follows:
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 (100) feet 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. In the event bridge
plugging is to be used for permanent abandonment, the bridge plug must be
covered with a minimum of ten (10) feet of cement; 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 (50) feet above
the top of the formation.
B. A
cement plug not less than one hundred (100) feet in length shall be placed at
approximately fifty (50) feet below all fresh water-bearing stratum when the
surface casing is not cemented below the base of the fresh water-bearing
stratum. In the event the surface casing has been cemented below the base of
the fresh water-bearing stratum, a one hundred (100) foot cement plug shall be
placed inside the base of the surface casing.
C. 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.
D. The interval
between plugs shall be filled with an approved heavy mud-laden fluid.
E. An uncased rotary drilling hole shall have
a cement plug of not less that one hundred (100) feet placed immediately above
(1) the Smackover limestone zone and (2) any known productive zone in the area,
and the hole shall be filled with approved heavy mud up to the base of the
surface casing and a plug of not less than one hundred (100) feet of cement
placed inside the base of the surface casing, provided the casing is cemented
through the base of the fresh water-bearing stratum. A cement plug of not less
than one hundred (100) feet in length shall be placed at a point fifty (50)
feet below the base of the fresh water-bearing stratum in the event the surface
casing is not cemented through the base of the fresh water-bearing stratum. The
hole shall be capped similar to other abandoned holes.
F. Any other method approved by the
Commission may be used. (Source: 1992 rule book)
RULE B-9:
DRY GAS WELL
PLUGGING METHODS AND PROCEDURES
a) Definitions:
1) "Cased Well" means a well in which
production casing has been set and cemented.
2) "Cement" means a class A or H neat cement
with a minimum weight of 14.5 pounds per gallon, unless the cement contains
additives which improve the ability of the cement to provide necessary
protection and which maintains a minimum compressive strength of 500 PSI after
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.
6) "Mud" means only a fresh-water based
drilling mud with a minimum weight of 9 pounds per gallon with a minimum
viscosity of 45 seconds using API Full Funnel Method. 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.
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 General Rule B-7.
2)
Notice of the plugging of uncased wells shall be given to the Commission
Regional Office where the well is located, in accordance with General Rule B-7.
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 (c)
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 ½ mile of the uncased well, shall have a one hundred (100) foot
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, at
a minimum, with a cement plug from one hundred (100) feet below to one hundred
(100) feet above the zone or 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 (500) feet in the well, a one hundred (100) foot
cement plug shall be placed, utilizing the circulation method, from a depth of
fifty (50) feet below the base of the surface casing,
or from the depth of any deeper freshwater well within ½ mile of the dry
hole, and extending fifty (50) feet into the cemented surface casing.
E) If surface casing has not been set to a
minimum depth of five hundred (500) feet in the well, a cement plug shall be
placed, from a depth of at least five hundred (500) feet or from the depth of
any deeper freshwater well within one-half (½) mile of the dry hole,
extending to fifty (50) feet 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 (50) feet below to fifty (50) feet 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 (50) feet to a depth of three (3) feet below the surface
of the ground and the casing cut off three (3) feet 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) 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. 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 may vary the plugging
requirements of this subparagraph and specify alternative plugging
requirements. In determining whether to approve and in selecting an alternative
plugging requirement, the Director shall consider the potential for damage to
fresh water, the depth of the lost tools or equipment in relation to the depth
of fresh water zones, well construction characteristics, and the potential for
upward migration of wellbore fluids into the fresh groundwater.
c) Cased Wells
1) Cased wells shall be plugged when required
by General Rule B-7.
2) Notice of
the plugging of cased wells shall be given to the Commission Regional Office
where the well is located, in accordance with General Rule B-7.
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.
C) If using the
circulation method, a cement plug of not less than one hundred (100) feet in
length, shall be placed from fifty (50) feet below, or total depth if well bore
did not extend to a point fifty (50) feet below, and extend across the
perforated interval, to a point fifty (50) feet above each perforated
interval.
D) 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 (10) feet of cement. 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
(50) feet above the top of the uppermost perforated interval, provided the
production casing/wellbore annulus is filled with cement to a point fifty (50)
feet above the uppermost perforated interval.
E) If cement is not present on the outside of
the production casing at the location of each required cement plug, specified
in F), G) and H) below, cement shall be placed on the
outside of the production casing in the production casing/wellbore annulus from
a point fifty (50) feet below, or total depth if the well bore did not extend
to a point fifty (50) feet below, and extending across the required interval to
be plugged, to a point fifty (50) feet above each required interval to be
plugged. However, the Director may approve alternative, but equally protective,
placement of cement plugs, openhole devices or plugging materials when
necessary due to well construction limitations.
F) 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 (50) feet below to
fifty (50) feet above the zone or a greater amount of cement sufficient to
shut-off the flow of water. 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 (500) feet in
the well, a one hundred (100) 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 (50) feet below the base of the surface casing,
or from the depth of any deeper freshwater well within ½ mile of the
wellbore, and extend fifty (50) feet into the cemented surface
casing.
H) If surface casing has
not been set to a minimum depth of five hundred (500) feet 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 (500) feet or from the depth of any deeper freshwater well within
½ mile of the well bore and extend fifty (50) feet into the cemented
surface casing present in the wellbore. 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 (50) feet below the existing surface casing and extending
fifty (50) feet into the cemented surface casing present in the
wellbore.
I) The casing shall be
cut off three (3) feet 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. A cement plug, not less than
three (3) feet, 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 subparagraph and specify alternative plugging
requirements.
B) In determining
whether to approve and in selecting alternative plugging requirements, the
Director shall consider the time and cost of removing lost tools or equipment,
the potential for damage to fresh water, the depth of the lost tools or
equipment in relation to the depth of fresh water zones, well construction
characteristics, and the 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 sub-paragraph (b) above with the
exception that (i) the production interval plug shall be placed at the
beginning of the well curve "kick-off point" and the required cement placed or
extend above that point, and (ii) 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 an cased well, the plugging procedures
shall be in accordance with sub-paragraph (c) above with the exception that (i)
the production interval plug shall be placed at the beginning of the well curve
"kick-off point" and the required cement placed or extend above that point, and
(ii) 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) 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 (100) 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.
Additionally, the Director may approve alternative forms of zonal isolation
based on the productive potential of the isolated zone.
4) Well-site clean-up shall be in accordance
with sub-paragraph (e) below.
e) Well Site Clean-Up
1) When plugging a well, the permit holder
shall provide at least one (1) pit as described in subparagraph e) 2) below, or
leak free, above ground, portable container into which plugging fluid wastes
shall be deposited.
2) 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. 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) All general oilfield wastes generated
during plugging activities shall be temporarily stored in on-site containers,
and shall be removed from the site at the conclusion of plugging activity.
General oilfield wastes shall not be disposed of through on-site burial or in
plugging pits.
4) 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. 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 (10) feet below the surface, at which point a cement
plug shall be placed from ten (10) feet to three (3) feet 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
maybe authorized by the Director, provided the same or equal level of
protection for the freshwater and oil and gas zones can be maintained.
(Original rule Repealed Effective October 15, 2006; new rule
March 25, 2010; amended October 1, 2015)
RULE B-10:
SEISMIC CORE AND
OTHER EXPLORATORY HOLES TO BE PLUGGED; METHODS, RECORDS
Before any hole is abandoned which is drilled for seismic, core
or other exploratory purposes below the fresh water 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.
A. 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 copy of
all electric logs shall be filed with the Commission no later than one (1) year
from the date drilling operations commence. 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.
(Source: 1992 rule book)
RULE B-11:
DOMESTIC NATURAL
GAS WELLS AND CONVERSION OF PERMITTED OIL AND NATURAL GAS WELLS FOR USE AS
DOMESTIC NATURAL GAS OR FRESH WATER SUPPLY WELLS
a) Domestic Natural Gas Wells
1) Any well drilled by persons for use as a
domestic, livestock or agriculture natural gas source, is not under the
jurisdiction of the 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. 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 all applicable
regulatory requirements of the Commission and any other applicable state laws
regarding the production, gathering and distribution of natural gas for use by
consumers.
b) Domestic
Use Transfer(s) 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, 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; and
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 owner(s), as defined in Ark. Code Ann. §
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; and
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 100 feet below
the base of the fresh water extending up to the base of the fresh water in the
well; and
C) All related surface
production equipment is removed from the well site.
3) 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. The well shall be subject to any applicable state laws
regarding private fresh water wells or domestic natural gas supply wells
administered by state and or federal agencies other than the Arkansas Oil and
Gas Commission.
c)
Uncontrolled natural gas production wells may not be transferred for domestic
use, unless otherwise approved the Commission after notice and a hearing.
Notice shall be given to all owner(s), as defined in Ark. Code Ann. §
15-72-102(9),
and all mineral owners in the leasehold upon which the well is located. Any
person requesting a transfer of an uncontrolled natural gas production well
shall file an application in accordance with General Rules A-2, A-3, and other
applicable hearing procedures.
d)
Domestic Use Transfer(s) 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 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.
(Source: 1992 rule book; amended November 16, 2008; amended May
18, 2012)
Rule Repealed Effective November 11, 2007
RULE B-13:
ORGANIZATION
REPORTS
a) Every person or
entity engaged in any operation or activity regulated by the Commission, shall
file with the Commission an organization report on a form prescribed by the
Director, prior to engaging in the operation or activity. At a minimum, the
form shall include:
1) Name of person or
entity and type of operation(s) being conducted;
2) An official mailing address to which all
correspondence from the Commission is to be sent. 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;
3) A list of official telephone number(s),
facsimile number(s), and e-mail address(es) for which contact by the Commission
may be made;
4) The type of entity,
and a list of all persons authorized to submit required forms, reports, and
other documents for the entity;
5)
A statement that the person or entity is authorized to conduct business within
the State; and
6) 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
1st 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.
(Source: 1992 rule book; amended January 22, 2009)
Rule Repealed Effective October 19, 2018 in accordance with Act
781 of 2017
RULE B-15:
CASING REQUIREMENTS
a. In all established fields, casing
requirements shall be governed by the specific field rules for that field, and
are not superceeded by this rule.
b. All fresh water sands shall be fully
protected by the setting and cementing of surface casing to prevent the fresh
water sands from becoming contaminated with oil, gas, or salt water. Surface
casing shall be set and cement circulated to surface utilizing the pump and
plug method. Cement shall be allowed to set a minimum of twelve (12) hours.
1. 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'
|
2. 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'
|
3. 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 500 feet
or the top of the Paleozoic age rock sequence, whichever is greater.
4. 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 1,250
feet.
5. 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 2,000 feet.
c. A
producing string of casing shall be set at least to the top of the producing
formation and shall be cemented so that the calculated fill, after allowing for
twenty-five percent excess, will be at least two hundred fifty feet above the
top of any productive interval. Cementing shall be done by the pump and plug
method. Cement shall be allowed to set a minimum of twenty-four (24) hours
before drilling the plug.
d. 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 fresh water sands and oil or gas bearing sands or may establish
minimum surface casing requirements in future producing areas not covered by
this rule.*
*Director's Notice to Fayetteville Shale Operators - June 1, 2015
(Supersedes previous version of June 1, 2011). 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 (please contact the El Dorado Regional office for
the zone map). The well casing and cementing requirements are as
follows:
1. Surface casing shall be
set to a depth equal to 500 feet below the lowest ground surface elevation
occurring within 1 mile of the proposed well, with a minimum of 1000 feet of
surface casing required to be set and cemented to surface.
2. 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 excess, shall be at a minimum of:
a. 100 feet above the surface casing shoe in
Zone 1;
b. 500 feet below the
surface casing shoe in Zone 2; and
c. 1500 feet below the surface casing shoe in
Zone 3.
3. If a gas
bearing zone is encountered above the Fayetteville Shale in the subject well or
in another well within a one (1) mile radius of the subject well, and the above
cementing requirements do not result in at least 250 feet of cement placed
above the shallow gas bearing zone, the TOC shall be increased to provide a
minimum of 250 feet of cement above the shallower gas bearing zone. However,
the additional cementing requirements in the subject well shall not result in
the production casing TOC to extend more than 100 feet above the surface casing
shoe inside the surface casing.
(Source: 1992 rule book; amended September 16, 2006)
RULE B-16:
BLOW-OUT PREVENTION
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 blow-out 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. Blow-out preventers shall be tested at
regular intervals to insure proper operation.
(Source: 1992 rule book; amended October 15, 2006)
RULE B-17:
WELL DRILLING
PITS AND COMPLETION PITS REQUIREMENTS
a) Applicability
This rule applies to all pits constructed during the drilling,
completion and testing of a brine, oil, gas, or oil and gas production well,
brine injection or disposal well, Class II Disposal Well, and Class II
Commercial Disposal Well. Pits as used in context of this rule refer to the
type pits as defined in subparagraph c) below.
b) Joint Enforcement
After the effective date of this rule, any Operator who
constructs or operates a pit covered by this Rule, shall be subject to the
specific enforcement provisions under the respective authorities of the
Arkansas Oil and Gas Commission (AOGC) or the Arkansas Department of
Environmental Quality (ADEQ). The regulation of the activities covered under
this rule by AOGC and ADEQ shall be in accordance with a Memorandum of
Agreement (MOA) between AOGC and ADEQ.
c) Definitions:
1) AOGC: Arkansas Oil and Gas
Commission.
2) ADEQ: Arkansas
Department of Environmental Quality.
3) APC & EC: Arkansas Pollution Control
and Ecology Commission.
4) Closed
Loop System: A system that uses a combination of solids control equipment
incorporated in a series of steel tanks that eliminates the use of a
Pit.
5) Completion Flow-Back Fluid:
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 Flow-Back Fluid.
6) Cuttings: 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.
7) Discharge: The release, overflow, leakage
or seepage of any fluids covered by this Rule.
8) Drilling Fluid: 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. Drilling Fluid is generally
synonymous with drilling mud, which typically contains bentonitic clays,
chemical additives, foaming agents, lubricants, emulsifiers and weighting
materials, and which encompasses most muds used in drilling operations,
especially muds that contain significant amounts of suspended solids,
emulsified water or oil. Mud includes all types of Water-Based, Oil-Based and
synthetic-based Drilling Fluids.
9)
Director of the ADEQ: The Director of the Arkansas Department of Environmental
Quality or his or her designated representative.
10) Director of AOGC: The Director of the
Arkansas Oil and Gas Commission or his or her designated
representative.
11) Ecologically
Sensitive Waterbody (ESW): Waters that have been given the designated use of
Ecologically Sensitive Waterbody by the Arkansas Pollution Control and Ecology
Commission. This beneficial use identifies segments known to provide habitat
within the existing range of threatened, endangered or endemic species of
aquatic or semi-aquatic life forms.
12) Encountered Water: Water encountered
during brine, oil, or gas drilling operations, which
is of sufficient quantity to require disposal, and which is not Produced
Water.
13) Exploration and
Production Waste (E&P Waste): 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, and may include, but are not limited to the
following: salt water (produced brine or produced water); Oil-Based Drilling
Fluids; Water-Based Drilling Fluids, Completion Flow-Back Fluid, Frac Flow-Back
Fluid, Workover Flow-Back Fluid, Produced Water; rainwater from firewalls and
Pits at drilling and production facilities; and other wastes not described
above.
14) Extraordinary Resource
Waters (ERW): Waters that have been given the designated use of Extraordinary
Resource Waterbody by the Arkansas Pollution Control and Ecology Commission.
This beneficial use is a combination of the chemical, physical and biological
characteristics of a water body and its watershed which is characterized by
scenic beauty, aesthetics, scientific values, broad scope recreation potential
and intangible social values.
15)
Frac Flow-Back Fluid: 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.
16) Natural and
Scenic Waterways (NSW): Waters that have been given the designated use of
Natural and Scenic Waterways by the Arkansas Pollution Control and Ecology
Commission. This beneficial use identifies segments which have been
legislatively adopted into a state or federal system.
17) Nonhazardous Oilfield Wastes (NOW):
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,
Drilling Fluids, completion fluids, surfactants, and chemicals used to detoxify
brine, oil, or gas wastes.
18)
Oil-Based Drilling Fluid: Drilling Fluid containing diesel or crude oil rather
than fresh water as the main liquid phase of the drilling mud.
19) Operator: Any person who has the primary
management and ultimate decision-making responsibility over the operation of a
facility or activity. The Operator is responsible for ensuring compliance with
all applicable rules and conditions.
20) Person: Natural person, corporation,
organization, municipality, government or governmental subdivision or agency,
public or private corporation, business trust, estate, trust, individual,
partnership, association, or any other legal entity.
21) Pit: shall include:
A) Circulation Pit: A pit used during
drilling where Drilling Fluids are circulated during drilling operations. The
Circulation Pit may be part of the Mud Pit. Circulation Pits may also refer to
a series of open, above-ground tanks, usually made of steel.
B) Completion Pit: A pit used for storage of
Completion Flow-Back Fluid and Drilling Fluids or other materials which have
been cleaned out of the well bore during the initial completion of a well.
Circulation or Mud Pits may be used as a Completion Pits when drilling
operations conclude.
C) Emergency
Pit: A pit used for containing fluids at an operating well during an actual
emergency and for a temporary period of time. Use of the Emergency Pit is
necessitated due to unplanned operational issues, which may include but is not
limited to, a temporary shutdown of a disposal well or fluid injection well or
associated equipment, temporary overflow of saltwater storage tanks on a
producing lease, gas flaring, cement circulation, or a producing well loading
up with formation fluids.
D) Mud
Pit: A pit or series of pits used during drilling where fluids are mixed and
circulated during drilling operations. Mud Pits may also refer to a series of
open, above-ground tanks, usually made of steel.
E) Reserve Pit: A pit not part of the active
circulation system, used to store Drilling Fluids or to contain fluids
generated during drilling operations. Such fluids would include, but not be
limited to, Cuttings, Drilling Fluids, and Encountered Water.
F) Test Pit: A pit constructed for use during
a well test.
G) Workover Pit: A pit
used for storage of Completion Flow-Back Fluid, Workover Flow-Back Fluid and
other materials which have been cleaned out of the well bore during any
subsequent completion or re-completion.
22) Pollution: 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 public health, safety, or welfare; to domestic,
commercial, industrial, agricultural, recreational, or other legitimate
beneficial uses; or to livestock, wild animals, birds, fish, or other aquatic
life.
23) Produced Water: Water
produced from any productive or potentially productive brine, oil, or gas
producing interval in the well, which is not Completion Flow-Back Fluid, Frac
Flow-Back Fluid, Workover Flow-Back Fluid, or Encountered Water.
24) Stormwater: Rainwater runoff, snow melt
runoff, and surface runoff and drainage.
25) Water-Based Drilling Fluid: Drilling
Fluid containing fresh waters rather than diesel or crude oil as the liquid
component of the drilling mud.
26)
Waters of the State: 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: The surface between the zone
of saturation and the zone of aeration and the surface of a body of unconfined
ground water at which the pressure is equal to that of the
atmosphere.
28) Workover Flow-Back
Fluid: 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
The Operator shall notify the appropriate AOGC Regional Office,
via mail, e-mail or fax, at least forty-eight (48) hours prior to the
commencement of Pit construction operations. The Notice of Commencement (NOC)
shall be on a form agreed upon by AOGC and ADEQ and shall include at a minimum
(i) the Operator information (name,
address, and emergency contact phone number),
(ii) the location of the drill pad site
(latitude and longitude in degrees, minutes, seconds, and County, Section,
Range, and Township, including the 1/4 of the 1/4 position within the
Section),
(iii) the approximate
size of the drill pad,
(iv) the
approximate distance to the nearest Waters of the State,
(v) the type of fluid system and type of
Drilling Fluids to be used,
(vi)
well name,
(vii) nearest
city/town, and
(viii) the
approximate date Pit construction operations shall commence. Upon receiving the
Notice of Commencement, AOGC shall forward a copy to ADEQ, Arkansas Department
of Health, and the County Judge of the county in which the pit is located. AOGC
and ADEQ staff may conduct site inspections as deemed necessary.
e) Discharges Prohibited
The Discharge from a Pit or any activity associated with the
drilling or completion of a well to any surface or ground waters or in a
location where it is likely to cause pollution to any surface or groundwaters
is prohibited. Such discharge may subject the Operator to ADEQ enforcement
actions under the provisions of the Water and Air Pollution Control Act (Act
472 of 1949, as amended, A. C. A. §
8-4-101, et seq.) and
enforcement actions of AOGC under Act 105 of 1939, as amended. Any Discharge
must be reported within twenty-four (24) hours to the AOGC and ADEQ. 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 100 year flood plain must be in accordance with any
county or other local ordinance or requirement pertaining to the 100 year flood
plain.
B) The location of all Mud,
Circulation or Reserve Pits shall be chosen with reasonable consideration to
maximizing the distance from surface waters. Mud, Circulation or Reserve Pit
construction in streams, creeks, lakes, or any other water bodies is strictly
prohibited.
C) Any Mud, Circulation
or Reserve Pit construction in wetlands must receive appropriate prior
authorization from the U.S. Army Corps of Engineers.
D) In areas other than jurisdictional
wetlands referenced in subparagraph f) 1) C) above, where the water table is
ten (10) feet or less below the ground surface, all Mud, Circulation or Reserve
Pits shall be constructed above ground, or the Operator shall use a closed loop
system.
2) Reserve Pit
Requirements:
A) All Reserve Pits shall be
constructed with a minimum of two (2) feet of freeboard, and shall be
maintained to handle a storm event up to a 10-year, 24-hour storm event during
the operation of the Reserve Pit. Reserve Pits constructed above ground
utilizing bermed side walls, shall be constructed with a minimum of 2:1 (two
feet horizontal to one foot vertical) side slope on both the interior and
exterior walls. The top of the bermed pit walls must be a minimum of 2 feet
wide.
B) All Reserve Pits shall be
constructed with a liner using one of the following methods:
i) A synthetic liner of at least twenty (20)
mils thickness, with a four (4) inch welded seam overlap, completely covering
the Reserve Pit bottom and inside walls. Sand or sandy material must be placed
below the liner if a rocky or uneven surface is encountered. The synthetic
liner must be protected from deterioration, punctures and/or any activity which
may damage the integrity of the synthetic liner.
ii) A compacted clay liner may be applied to
the bottom and sides of the Reserve Pit to create an impervious/impermeable
barrier. 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 Waters of the State, with due
consideration given to the topography, Pit material composition, and
availability of liner material(s). 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.
iii) Other materials or
methods used for liner construction must be approved by both the Director of
the ADEQ and the Director of the AOGC prior to use.
3) Mud and Circulation Pits:
A) Closed Loop Systems may be used for Mud
and Circulation Pits, and must be maintained in a leak-free
condition.
B) Earthen Mud and
Circulation Pits shall be constructed with a minimum of two (2) feet of
freeboard, and shall be maintained to handle a storm event up to a 10-year,
24-hour storm event during the operation of the Mud or Circulation
Pit.
C) Earthen Mud and Circulation
Pit liners shall be constructed using one of the following methods:
i) A synthetic liner of at least twenty (20)
mils thickness, with a four (4) inch welded seam overlap, completely covering
the Reserve Pit bottom and inside walls. Sand or sandy material must be placed
below the liner if a rocky or uneven surface is encountered. The synthetic
liner must be protected from deterioration, punctures and/or any activity which
may damage the integrity of the synthetic liner.
ii) Bentonite drilling mud from fresh
Water-Based Drilling Fluids may be used on the bottom and sides of the earthen
Mud or Circulation Pit to create an impervious/impermeable barrier. 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.
iii) A concrete liner may be applied to the
bottom and sides of the earthen Mud or Circulation Pit to create an
impervious/impermeable barrier. 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
subparagraph f) 3) C) i) or iii) above.
E) If Oil-Based Drilling Fluids are to be
used, and the location of the Mud or Circulation Pit is within 100 feet 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
Flow-Back Fluid may not be placed, stored or disposed in a Mud, Circulation, or
Reserve Pit, except that as part of a Frac Flow-Back Fluid recycling program,
Frac Flow-Back Fluids, and upon approval of both AOGC and ADEQ Directors,
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 subparagraph f) 2) B) ii) above and a synthetic liner of
at least forty (40) mils thickness, or two (2) twenty (20) mils thickness
synthetic liners, in addition to all other applicable Reserve Pit construction
requirements as specified in subparagraph f) 2) above, and have a means to
monitor between the synthetic liners (if two liners are utilized) and below the
bottom of the lower most synthetic liner; and
B) The Operator requests approval from ADEQ
in writing prior to the placement or storage of the Frac Flow-Back Fluid or
approved Produced Water, in a Reserve Pit. Such request shall include the AOGC
Well Permit Number, well names(s), description of the water to be stored,
anticipated dates of use, volume of water to be stored or placed, detailed
information on any proposed pipelines for the transfer Frac Flow-Back Fluids
including a map showing proposed pipeline location for; and
C) No Frac Flow-Back Fluids or other fluids
mixed with Frac Flow-Back Fluids temporally stored or placed in a Reserve Pit
may be sent to any commercial land applications disposal facility or land
applied onsite.
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) Mud, Circulation
and Reserve Pits must be maintained in such a manner as to prohibit any
Discharges. The Operator is required to maintain adequate storage capacity at
all times.
5) Mud, Circulation and
Reserve Pit levees or walls shall be protected and maintained at all times to
prevent deterioration or discharge. 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) 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
Flow-Back Fluid recycling program a Reserve Pit, permitted in accordance with
subparagraph g) 2) above, may temporarily contain Frac Flow-Back Fluids and
upon approval by both AOGC and ADEQ Directors, Produced Water, which may be
transferred to another drill pad Reserve Pit permitted in accordance with
subparagraph g) 2) above. The transfer of Frac Flow-Back Fluids and approved
Produced Water, via tank truck, shall be in accordance with General Rule E-3.
If the transfer of Frac Flow-Back Fluids and approved Produced Water, is via
pipeline, such pipeline shall be constructed and maintained in a leak-free
condition and protected from deterioration, punctures and/or any activity which
may damage the integrity of the pipeline. If the proposed pipeline will result
in a stream crossing, a short term activity authorization shall be received
from the ADEQ prior to construction. Any discharge from the pipeline shall be
reported immediately to ADEQ.
7) In
the event of an emergency and with prior approval from either the Director of
ADEQ or the AOGC, the Reserve Pit may be used for temporary additional storage
of Water-Based Drilling Fluids from another drilling pad location. In the event
of an emergency, any request for approval must be submitted to both ADEQ and
AOGC for review. ADEQ or AOGC will provide notice to each other at the time of
the approval of any request made pursuant to this paragraph.
8) Except as specified in subparagraph i) 1),
or in an emergency and with prior approval from the Director of the ADEQ
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
of the following manners:
A) Land applied in
accordance with an active ADEQ land application permit.
B) Disposed of fluid into approved NPDES or
state permitted facility.
C)
Injected via Class II wells permitted by AOGC.
D) Pumping the Water-Based Drilling Fluids
back down the well bore of the well in accordance with AOGC
requirements.
E) 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. 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 Flow-back Fluid recycle program.
G) By any other method as approved by ADEQ
and AOGC.
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 AOGC or ADEQ 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) The closed Pit shall be filled with native
materials and covered with topsoil at depths consistent with adjoining onsite
areas, with the contour mounded or sloped to discourage erosion and restored as
close to the original contours as is practicable. Topsoil and native materials
removed during Pit construction may be preserved and used during
closure.
5) The oil & grease
content of the material to be buried in situ shall be less than 3% by dry
weight.
6) 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 days (180) days after the drilling or workover rig
is removed from the site, or in the case of a multiple well drill pad, within
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 rule. An
extension of the time to close the pit may be granted upon approval of both
AOGC and ADEQ. Vegetative coverage of 75%, or equivalent to the surrounding
landscape, whichever is less, shall be obtained within six (6) months of Pit
closure. Until vegetation is established, the Operator is responsible for
maintaining a stormwater erosion and sediment control plan.
7) The Operator shall submit the Notice of
Pit closure to AOGC signed by the Operator within 30 days after Pit closure has
been completed. AOGC shall forward a copy to ADEQ.
i) Fluid Disposal and Earthen Pit Closure
Requirements for Oil-Based Drilling Fluids.
1) Oil-Based Drilling Fluids shall be removed
from the Pit and hauled to a permitted Class 1 (as defined by APC&EC Rule
No. 22) landfill for disposal or be transferred to above ground tanks for
re-use at another well location, or other disposal methods or uses of Oil-Based
Drilling Fluids as approved by the ADEQ. The Operator shall inform the AOGC of
the location of the disposal or transfer of the Oil-Based Drilling Fluid. AOGC
shall forward a copy to ADEQ.
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 ADEQ.
3) Any synthetic liner used shall be removed
to the fullest extent practicable and properly disposed or recycled.
4) The closed Pit shall be filled with native
materials and covered with topsoil at depths consistent with adjoining onsite
areas, with the contour mounded or sloped to discourage erosion and restored as
close to the original contours as is practicable. Topsoil and native materials
removed during Pit construction may be preserved and used during
closure.
5) The area shall be
returned to grade, reclaimed and seeded within a reasonable amount of time not
to exceed one hundred eighty days (180) days after the drilling rig is removed
from the site. Vegetative coverage of 75%, or equivalent to the surrounding
landscape, whichever is less, shall be obtained within six (6) months of
closure. Until vegetation is established, the Operator is responsible for
maintaining a stormwater erosion and sediment control plan.
6) The Operator shall submit the Notice of
Pit closure to AOGC signed by the Operator within 30 days after Pit closure has
been completed. AOGC shall forward a copy to ADEQ.
j) Requirements for Workover Pits, Emergency
Pits and Test Pits
1) No Produced Water,
Workover Flow-Back 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 subparagraph f) 2) B) above.
2) All Workover, Emergency, or Test Pits
shall be closed within thirty (30) days after the associated workover,
emergency, or test ceases. Any Workover, Emergency, or Test Pit shall be closed
in accordance with the requirements of subparagraph h) above.
k) Other drilling mud systems not
specifically authorized by this Rule shall require prior notification and
approval by the Director of the AOGC and the Director of ADEQ.
l) Stormwater Erosion and Sediment Controls
1) The Operator shall prepare a stormwater
erosion and sediment control plan for the well site covered by this rule. The
plan shall be prepared in accordance with proven and accepted engineering
practices. 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). Facilities shall implement the provisions of the plan required under
this rule. The Operator shall provide upon request by the ADEQ or AOGC 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 water bodies
previously submitted and approved by ADEQ.
3) Any facility that potentially discharges
stormwater runoff to a water body listed for siltation pursuant to Section
303(d) of the Clean Water Act, or an ERW, ESW or a 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. The 303(d) list, and the location of ERW, ESW, and
NSW waters are available from ADEQ's website at the following address:
http://www.adeq.state.ar.us/water/.(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)
RULE B-18:
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.
(Source: 1992 rule book)
RULE B-19: REQUIREMENTS FOR
WELL COMPLETION UTILIZING FRACTURE STIMULATION
a) Definitions
1) "ADEQ" means the Arkansas Department of
Environmental Quality.
2)
"Additive" means any substance or combination of substances, including
proppant, having a specified purpose that is combined with a Hydraulic
Fracturing Fluid.
3) "AOGC" means
the Arkansas Oil and Gas Commission.
4) "Chemical Abstract Service" or "CAS" means
the chemical registry that is the authoritative collection of disclosed
chemical substance information.
5)
"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.
6) "Chemical Family"
means a group of elements in the Periodic Table or, more commonly, compounds
that share certain physical and chemical characteristics and have a common
name.
7) "Hydraulic Fracturing
Fluid" means the base fluid type utilized in a particular Hydraulic Fracturing
Treatment.
8) "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.
9) "RCRA" means
Resource Conservation and Recovery Act,
42 U.S.C. §
6901 et. seq.
b) The provisions of this Rule shall apply to
all new horizontal wells and all vertical wells in which the amount of
Hydraulic Fracturing Fluid used during the Hydraulic Fracturing Treatment of
the well exceeds 10,000 barrels Hydraulic Fracturing Fluid and for which an
initial drilling permit was issued on or after January 15, 2011.
c) 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 subparagraph d) below. 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 subparagraph d) below via e-mail,
fax or mail to the AOGC office where the initial drilling permit was issued,
prior to commencement of Hydraulic Fracturing Treatment operations.
d) The application described in subparagraph
c) 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 vertical well,
a directional well, or a horizontal well; and
B) The estimated true vertical and measured
production casing setting depths; and
C) The casing grade and minimum internal
yield pressure for the production casing proposed to be used in the
well.
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.
3) The anticipated surface treating pressure
range for the proposed Hydraulic Fracturing Treatment program. The production
casing described in subparagraph d) 1) above shall be sufficient to contain the
maximum anticipated treating pressure of the Hydraulic Fracturing Treatment,
which shall not exceed 80% of the minimum internal yield pressure for such
production casing.
e)
Surface casing in the well in which the proposed Hydraulic Fracturing Treatment
will occur shall be set, and cemented to the surface, to a depth in accordance
with General Rule B-15, and have sufficient internal yield pressure to
withstand the anticipated maximum pressures to which the casing will be
subjected in the well. 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 freshwater 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 (100) feet below the deepest encountered
freshwater zone.
f) 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 Rule, 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, or
his designee, in writing as soon as practicable, but not more than twenty-four
(24) hours after the event. In reviewing the report, the Director, or his
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) The Permit Holder shall notify the
Director or his designee via e-mail, fax or other approved method, a minimum of
forty-eight (48) hours prior to commencement of a Hydraulic Fracturing
Treatment on a well. If the Permit Holder cannot provide notice a minimum of
forty-eight (48) hours 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) 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. The Permit
Holder shall establish methods to timely relieve any excessive pressures to
avoid the loss of surface casing integrity.
i) The Permit Holder must provide written
notice to the Director, or his designee, of
(i) any change in surface casing annulus
pressure that would indicate movement of fluids into the annulus, or
(ii) a pressure that exceeds the rated
minimum internal yield pressure on any casing string in communication with the
Hydraulic Fracturing Treatment. This written notice shall be delivered as soon
as possible after the event, but not more than twenty-four (24) hours after the
event. Following notification and any request for additional information, the
Director, or his designee, may request additional documentation or well tests
to determine if the Hydraulic Fracturing Treatment potentially endangered any
freshwater zones. The Director, or his designee, may require appropriate
additional cementing operations, or other well workover efforts to correct any
well failure. Pending completion of required operations or efforts, the
Director, or his designee, may order the cessation of further Hydraulic
Fracturing Treatment and/or other well operations. 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) All non-exempt RCRA materials and fluids
used on-site in the Hydraulic Fracturing Treatment shall be handled and stored
in accordance with ADEQ requirements and any spills of these materials and
fluids on-site or off-site shall be reported to ADEQ in accordance with
applicable ADEQ requirements. 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. 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 designee,
within twenty-four (24) hours.
k)
All Hydraulic Fracturing Treatment flow back fluids shall be handled,
transported, stored, disposed, or recycled for re-use in accordance with the
applicable provisions of General Rule B-17, General Rule E-3 and General Rule
H-1, H-2 and H-3.
l) Following
completion of the Hydraulic Fracturing Treatment, the Permit Holder shall, for
purposes of disclosure, report detailed information to the Director, or his
designee, of the Hydraulic Fracturing Treatment in the manner customarily
reported or presented to the Permit Holder, within the time period specified in
General Rule B-5, as follows:
1) The maximum
pump pressure measured at the surface during each stage of the Hydraulic
Fracturing Treatment; and
2) The
types and volumes of the Hydraulic Fracturing Fluid and proppant used for each
stage of the Hydraulic Fracturing Treatment; and
3) The calculated fracture height as designed
to be achieved during the Hydraulic Fracturing Treatment and the estimated TVD
to the top of the fracture; and
4)
A list of all Additives used during the Hydraulic Fracturing Treatment
specified by general type, such as acid, biocide, breaker, corrosion inhibitor,
crosslinker, demulsifier, friction reducer, gel, iron control, oxygen
scavenger, pH adjusting agent, scale inhibitor, proppant and surfactant;
and
5) The names of all specific
Additives for each Additive type, specified in subparagraph l) 4) above,
utilized during the Hydraulic Fracturing Treatment and the actual rate or
concentration for each such Additive expressed as pounds per thousand gallons
or gallons per thousand gallons additionally, the Additives are to be expressed
as a percent by volume of the total Hydraulic Fracturing Fluids and Additives;
and
6) 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; and
7) The Permit Holder shall supply all
information received from the person performing the Hydraulic Fracturing
Treatment specified in subparagraph m) 4) below.
8) 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; 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 subsection (a)(2) of
42
U.S.C. §
11042, the Permit Holder shall
(i) submit to the Director a claim of
entitlement to have the identity of such Chemical Constituent withheld as a
trade secret, and
(ii) provide the
Director with the Chemical Family associated with such Chemical Constituent.
The identity of any Chemical Constituent that qualifies as a trade secret under
the criteria set forth in subsection (a)(2) of
42
U.S.C. §
11042 shall be held
confidential by the Director.
9) Nothing in subparagraph l) 8) above shall
authorize any person to withhold information which is required by state or
federal law to be provided to a health care professional, a doctor, or a nurse.
All information required by a health care professional, a doctor, or a nurse
shall be supplied, immediately upon request, by the person performing the
Hydraulic Fracturing Treatment, directly to the requesting health care
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; and
2) Be required to file Organization Reports
in accordance with General Rule B-13, and include the length of time the entity
has been in the business of performing Hydraulic Fracturing Treatments;
and
3) Disclose to the Director, or
his 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; and
B) All Additives to
be utilized during any Hydraulic Fracturing Treatment within the State of
Arkansas; and
C) All Chemical
Constituents and associated CAS numbers to be utilized in any Hydraulic
Fracturing Treatment within the State of Arkansas; 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 subsection (a)(2) of
42
U.S.C. §
11042, the person performing
the Hydraulic Fracturing Treatment shall
(i)
submit to the Director a claim of entitlement to have the identity of such
Chemical Constituent withheld as a trade secret, and
(ii) provide the Director with the Chemical
Family associated with such Chemical Constituent. The identity of any Chemical
Constituent that qualifies as a trade secret under the criteria set forth in
subsection (a)(2) of
42
U.S.C. §
11042 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; and
B) 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; 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 subparagraph l) 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
subparagraph m) 3) c) above.
5) Nothing in subparagraphs m) 3) c) or l) 4)
c) above shall authorize any person to withhold information which is required
by state or federal law to be provided to a health care professional, a doctor,
or a nurse. All information required by a health care professional, a doctor,
or a nurse shall be supplied, immediately upon request, by the person
performing the Hydraulic Fracturing Treatment, directly to the requesting
health care 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.
n) 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
subparagraph m) above.
(Source: Original Rule Repealed October 15, 2006; New Rule
Effective January 15, 2011; Amended February 08, 2013; Amended July 15,
2017)
RULE B-20:
REPEALED
Rule Repealed Effective October 15, 2006
RULE B-21:
REPEALED
Rule Repealed Effective October 15, 2006
RULE B-22:
REPEALED
Rule Repealed Effective November 11, 2007
RULE B-23:
TUBING
a) All oil wells shall be equipped with, and
produced through tubing. Bottom of tubing on flowing wells shall not be higher
than top of producing interval. If tubing is perforated, the perforations shall
not extend above the top of the producing interval.
b) 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. If multiple gas zones are produced in the
well, authority to commingle in accordance with General Rule D-18 shall be
required.
(Source: 1992 rule book; amended October 15, 2006)
RULE B-24:
REPEALED
Rule Repealed Effective October 19, 2018 in accordance with Act
781 of 2017
RULE B-25:
REPEALED
Rule Repealed Effective November 11, 2007
RULE B-26:
GENERAL LEASE
OPERATING REQUIREMENTS
a)
Definitions for purposes of this rule
1)
"ADEQ" means the Arkansas Department of Environmental Quality.
2) "Crude Oil Tank Battery" means crude oil
storage tanks and other vessels commonly used in the production and temporary
storage of crude oil.
3) "Director"
means the Arkansas 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 the owners of the oil and gas
rights under that tract of land.
7)
"Permit Holder" shall mean 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 others.
8) "Produced
Fluids" shall mean those fluids produced or generated during the crude oil
production and separation process and shall include crude oil, crude oil bottom
sediment and shall include 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.
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
B) contains a sufficient
quantity of groundwater to supply a public water system and currently supplies
drinking water for human consumption or contains fewer than 10,000 mg/l total
dissolved solids; and
C) Which is
not an exempted aquifer (see 40 CFR).
b) Well Identification
1) 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 Commission records. If the lease
is a single well lease, the well sign may be placed at the associated tank
battery or lease entrance.
2) Every
entrance from a public road to north Arkansas gas well sites shall have a
legible sign placed at that entrance. The sign shall show the name of the
Permit Holder, a list of all wells accessed by that entrance, the section,
township and range, and a telephone number at which the Permit Holder or his
authorized agent can be reached during an emergency.
3) For any newly drilled well, the required
sign shall be posted within 45 days after cessation of drilling
operations.
4) Any changes or
corrections in the well information, required to be posted in accordance with
this rule, 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 Commission records.
All prior signs, if not correct, shall be removed.
c) Crude Oil Tank Batteries and Oil Well
Produced Fluids Storage Tanks
1) All existing
and newly constructed Crude Oil Tank Batteries and Oil Well Produced Fluids
Storage Tanks shall be registered with the Commission and assigned a Commission
registration number. Registration shall be reported to the Commission utilizing
information as reported on the existing AOGC Form 6 Monthly Producers
Report.
2) All Crude Oil Tank
Battery and Oil Well Produced Fluids Storage Tanks registrations, shall be
transferred, at the time of associated well transfers, utilizing the approved
notice of well transfer forms filed with the Commission.
3) Each Crude Oil Tank Battery and Oil Well
Produced Fluids Storage Tanks shall have a legible sign in a conspicuous place
on or near the near the crude oil storage tank(s). The sign shall show the name
of the Permit Holder who holds the Commission permit to operate the lease or
unit, the lease name, the section, township and range, and a telephone number
at which the Permit Holder or his authorized agent can be reached during an
emergency.
4) 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. All containment dikes or other
approved structures shall be constructed or installed in accordance with
sub-paragraph (e) below.
5) All
Crude Oil Tank Batteries and Oil Well Produced Fluids Storage Tanks,
constructed after the effective date of this rule, shall not be located:
A) within 200 feet of an existing occupied
habitable dwelling, unless the current owner of the structure has provided a
written waiver consenting to the construction closer than 200 feet, in which
case the tank battery shall be completely fenced to prevent unauthorized
access; however, in no event may a tank battery may be constructed closer that
100 feet to an existing habitable dwelling; or
B) within 300 feet of a school, hospital or
other type of public use building as defined in Arkansas Fire Prevention Code
Section 3406.3.1.3.1; or
C) within
300 feet of a stream or river designated as an Extraordinary Resource Water
(ERW), Natural and Scenic Waterways or Ecological Sensitive Waterbodies as
defined by APC&E Rule 2, or within 200 feet 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 7.5 minute USGS Topographic Map), unless the Permit Holder
utilizes additional containment measures other than the required containment
specified in sub-paragraph (e) 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 rule, shall not be located:
A) within
200 feet of an existing occupied habitable dwelling, unless the current owner
of the structure has provided a written waiver consenting to the construction
closer than 200 feet, in which case the tank battery shall be completely fenced
to prevent unauthorized access; however, in no event may a tank battery may be
constructed closer that 100 feet to an existing habitable dwelling;
or
B) within 300 feet of a school,
hospital or other type of public use building as defined in Arkansas Fire
Prevention Code Section 3406.3.1.3.1; or
C) within 300 feet of a stream or river
designated as an Extraordinary Resource Water (ERW), Natural and Scenic
Waterways or Ecological Sensitive Water bodies as defined by APC&E Rule 2,
or within 200 feet 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 7.5 minute USGS
Topographic Map), unless the Permit Holder utilizes additional containment
measures other than the required containment specified in sub-paragraph (e)
below, as approved by the Director.
5) 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. All containment dikes or other approved structures
shall be constructed or installed in accordance with sub-paragraph (e)
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 Commission following notice and hearing.
2) Required containment dikes or other
approved structures shall be designed to have a capacity of at least 1½
times the largest tank the containment dike or approved structure
surrounds.
3) The natural or
man-made material utilized for the construction of the required containment
dikes or other approved structures and the natural or man-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) 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. 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. Any
fluids collected, spilled or discharged within such containment structures
shall be removed as soon as practical, using the following proper disposal
methods:
A) Stormwater, which has not been
mixed with non-exempt RCRA waste as defined by the EPA, may be drained from the
containment structure provided the following conditions are met:
i) the chloride content shall not exceed
applicable state water quality standards.
ii) there must be no visible evidence of
hydrocarbons or hydrocarbon sheen present;
iii) the discharge shall only take place
during daylight hours;
iv) a
representative of the Permit Holder must be present during discharge; and
v) the Permit Holder shall
maintain a record of each stormwater discharge, occurring in the previous 6
month period, and which shall be available for review upon request by
Commission staff. The record shall indicate the location, quantity, chloride
content, presence of any hydrocarbons (sheen), and date of
discharge.
B) Produced
fluids which have not been mixed with non-exempt RCRA waste as defined by the
USEPA, may be recycled through the production equipment or removed from the
containment structure and disposed in a properly permitted Class II UIC
Well.
C) All stormwater and
produced fluids which have been mixed with non-exempt RCRA waste as defined by
the USEPA shall be removed and disposed in accordance with applicable Pollution
Control and Ecology Commission rules, as administered by ADEQ.
D) Crude oil bottom sediments (BS&W) may
be:
i) applied on oil field lease roads under
the following conditions:
a) application shall
be in such a manner as to avoid runoff onto immediately adjacent lands or into
Waters of the State; and
b)
immediately following completion of the application, all liquid fractions shall
be immediately incorporated into the road bed with no visible free-standing
oil; and
c) no lease road shall be
oiled more than twice a year; and
d) no lease road shall be oiled during
precipitation events; and
e) the
applied BS&W shall not have a produced water content greater than ten
percent (10%) free water by volume; or
ii) injected into an inactive oil and gas
production well:
a) 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 (50) feet below the top of the
production casing cement, but no less than five hundred (500) feet below the
base of the deepest USDW, and
b)
injection of the BS&W shall not exceed 45 days, after which time the well
shall be immediately plugged in accordance with General Rule B-8, and
c) 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 subsection (e) (5)
above, shall be remediated in place in accordance with General Rule
B-34.
7) Any spill, leak or
discharge of produced fluids escaping from a containment dike shall be reported
and remediated in accordance with General Rule B-34.
8) When a Crude Oil Tank Battery, Oil Well
Produced Fluids Storage Tanks, or Gas Well Produced Fluids Storage Tank or a
gas well separator is removed, the Permit Holder shall remove all above ground
piping and flowlines coming into said tanks or separator and cap all below
ground piping and flowlines, level and grade soil portion of the containment
dikes, remove from site all non-soil containment structure construction
material, and remediate all hydrocarbon contaminated soil at tank or separator
site in accordance with General Rule B-34.
f) Liquid Hydrocarbon Flowlines and Produced
Fluid Flowlines
1) All flowlines used in the
production of liquid hydrocarbons, constructed after the effective date of this
rule, shall be buried at least twenty-four (24) inches below the ground
surface. Flowlines may be exempt from these burial requirements upon approval
of the Director, in the following circumstances:
A) the topographical features, land uses or
ground conditions prevent the efficient burial of flowlines; or
B) the suspected presence of numerous old
abandoned flowlines, in old producing fields, render the burial of new lines
impractical or which will significantly increase the likelihood of causing the
discharge of crude oil from the old lines; or
C) the terms of the oil and gas lease or
surface owner agreement, prohibit the burial of flowlines; or
D) the flowlines are installed or placed
within the lease road right of way; or
E) the 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 rule to be
replaced, buried or constructed in accordance with subsection (2) 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) 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. 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 General Rule
B-34.
g) Natural gas
production lines and gathering lines shall be installed and operated in
accordance with General Rule D-17 - General Rule Relative to Establishing An
Effective And Efficient Procedure For The Regulation Of Production Field Lines
For Natural Gas As Well As Safety Standards or other applicable Commission
rules.
h) Power Lines
1) All power lines installed after the
effective date of this rule, 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 rule, to be in
compliance with sub-paragraph (h) (1) 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 well head 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) 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. All
used refined oil shall be disposed in accordance with Arkansas Pollution
Control and Ecology Commission Rule 23, 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 site(s)
or production area(s), and are maintained and kept free of excessive
vegetation.
5) Other trash and
debris, including but not limited to, abandoned, unusable or unrepairable, junk
tanks, treaters, tubulars, injection pumps, pump jacks, concrete, above ground
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.
Removed trash and debris shall be disposed in accordance with applicable ADEQ
or other state agency rules.
j) Production Pits
1) "Production Pit", as used in this Section,
is an earthen surface impoundment, whether a man-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 Commission
Orders are prohibited.
3) All other
production pits in existence as of the effective date of this rule shall cease
to be used on the effective date of this rule and closed within 90 days after
the effective date of this rule in a manner prescribed by the Commission and in
accordance with all applicable state laws and rules, unless exempted in
accordance with subsection (4) below.
4) Any production pit in existence as of the
effective date of this rule, may not be subject to closure in accordance with
subsection (j) (3) above if:
A) the pit is no
longer used for temporary storage of produced fluids; and
B) the water quality in the pit is less than
1500 TDS with no visible sheen of oil; and
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:
i) review the current location of the pit
relative to any ongoing production operations in the area; and
ii) review the proposed alternative use
relative to public health and safety considerations and potential use for
agricultural, recreational or wildlife habitat purposes.
E) 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 subsection (3) above.
k) Leaking Permitted Well
Where any oil and gas reservoir fluids or salt waters 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. Pending plugging of the well, all injection wells within a
1/4 mile radius of the leaking drill hole shall be shut-in until the well is
plugged.
l) Leaking
Previously Plugged Well
Where any oil and gas reservoir fluids or salt waters are
potentially leaking into the USDW or to the surface as determined by geologic
and field investigation, through a well plugged under applicable Commission
rules, the well shall be replugged by the original Permit Holder responsible
for plugging the leaking well. If the original Permit Holder is no longer in
existence or cannot be located, the well shall be eligible for plugging through
the Arkansas Orphan and Abandoned Well Plugging Fund. Pending plugging of the
well all injection wells within a 1/4 mile radius of the leaking well shall be
shut-in until the leaking well is plugged.
(Source: 1992 rule book; amended July 13, 2003; amended October,
14, 2007; amended August 17, 2008; amended June 16, 2019)
RULE B-27:
REPEALED
Rule Repealed Effective July 15, 2017
RULE B-28:
REPEALED
Rule Repealed Effective November 11, 2007
RULE B-29:
REPEALED
Rule Repealed Effective October 15, 2006
RULE B-30:
DEVIATION
TESTS
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. Deviations in excess of the following shall be
deemed to be unreasonable: More than 3 degrees from the vertical drawn from the
center of the hole at the surface.
The Commission shall have the right to make, or to require the
operator to make a directional survey of the hole, under the following
circumstances:
(a) 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; (b)
prior to a permit being issued, if an off-set operator requests a directional
survey and agrees in writing to pay all costs and expenses of such survey and
to assume liability for all risks associated with the survey and further posts
a bond in sufficient sum as determined by the Commission as security against
all costs and risks associated with the survey or, (c) 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. The Commission shall have the continuing jurisdiction to
assess the expense and risk of such survey between the operator and any
opposing party.
(Source: 1992 rule book; amended July 13, 2003)
RULE B-31:
REPEALED
Rule Repealed Effective October 15, 2006
RULE B-32:
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 Commission or in accordance
with subparagraph b) below.
b)
Administrative Approval. The Director or his 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 Ark. Code Ann. (1987) §
15-72-102(9)
and no objections were received by the Director in accordance with subparagraph
b) 6) 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 Ark. Code Ann. (1987) §
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 subparagraph b) 4) 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 Ark. Code Ann. (1987) §
15-72-102(9),
and the date(s) of mailing.
6) Any
owner, as defined by Ark. Code Ann. (1987) §
15-72-102(9),
noticed in accordance with subparagraph b) 5) 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. Each objection must be made in
writing and filed with the Director or his designee. 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. If the application is
denied under this subparagraph, the applicant may file an application for
hearing in accordance with General Rules A-2 and A-3, and other applicable
hearing procedures.
7) An
application may be referred to the Commission for determination when the
Director or his 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. Promptly upon such
determination, and not later than fifteen (15) days after receipt of the
application, the Director or his designee shall give the applicant written
notice, citing the reason(s) for referral to the full Commission for
determination, and the application shall be denied. If the application is
denied under this subparagraph, the applicant may file an application for
hearing in accordance with General Rules A-2 and A-3, and other applicable
hearing procedures.
8) If the
Director has not notified the applicant of the determination to refer the
application to the Commission within the fifteen (15) 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 subparagraph b)
6), the application shall be approved.
(Source: 1992 rule book; amended July 29, 2011)
RULE B-33:
REPEALED
Rule Repealed Effective July 15, 2017
RULE B-34:
NOTICE OF FIRE,
BREAKS, OR BLOW-OUTS AND REMEDIATION OF ASSOCIATED SPILLS OF CRUDE OIL AND
PRODUCED WATER
a)
Definitions for purposes of this rule
1)
"Permit Holder" shall mean 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 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, notify the Commission Regional Office, where the event has occurred, by
telephone or facsimile concerning all fires, blow-outs, 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) 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, blow-out,
spill leak, or discharge by providing the Section, Township, Range and
property, lease, or unit, name. 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,
blow-out, 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:
A) the amount of crude oil and produced water
spilled or discharged,
B) the areal
extent of the spill or discharge,
C) the cause of the spill or discharge,
and
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 rule and
are under the jurisdiction of the Arkansas Department of Environmental Quality
(ADEQ).
5) All crude oil and
produced water spills or discharges, regardless of amount, which enter Waters
of the State as defined in Ark. Code Ann. §
8-4-102 shall be
reported immediately to the ADEQ. That portion of the spill which entered
Waters of the State shall be under the jurisdiction of the ADEQ for remediation
and enforcement purposes.
c) Crude Oil Spill Remediation Requirements
1) All crude oil spills that occur after the
effective date of this rule, regardless of amount,
from wells, flowlines, tanks, pits or containment dikes are
subject to this rule.
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 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) If a spill enters surface waters, the
spill shall be contained with booms and/or underflow dams and removed as
expeditiously as possible. Further remediation requirements shall be determined
by ADEQ in accordance with sub-paragraph (a) (5) above.
C) The cause of spill shall be repaired
immediately.
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
non-organic/non-biodegradable absorbent materials shall be removed from the
site and disposed of at an ADEQ 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 sub-paragraphs (4) (A) thru (D) below.
4) Contaminated soil area affected by a spill
may be remediated in place and shall, within 10 days, at a minimum be:
A) fertilized with 13-13-13 fertilizer or an
amount of other acceptable fertilizer sufficient to treat the soil with 0.5 lbs
per square yard; and
B) limed with
sufficient agricultural grade lime over the affected area in order to maintain
a pH of between 6-8; if the pH of the soil/oil mixture is less than 6,
additional lime shall be incorporated to increase pH above 6; and
C) tilled to a depth of at least 4 inches but
no greater than 12 inches to create a soil and crude oil mixture that contains
less than 5% total petroleum hydrocarbon (TPH) following the completion of the
initial tilling; and
D) watered to
maintain soil moisture sufficient to promote plant growth (if extremely dry
soil conditions exist); and
E)
stabilized to minimize erosion and run-off of stormwater to prevent violation
of applicable water quality standards.
F) If the soil in the affected area is frozen
or previously saturated due to rain or snow melt, prohibiting compliance with
sub-paragraphs (A) thru (E) above, the Permit Holder shall stabilize the area
to prevent any surface run-off of crude oil from leaving the affected area
until conditions permit compliance with sub-paragraphs (A) thru (E)
above.
G) The soil affected by the
spill must contain less than 1% TPH within 12 months after the date of the
spill.
H) The Director may require
additional remediation action to be taken by the operator, which may include
flushing of the area with freshwater (which shall be collected and disposed in
a UIC Class II well), the addition of organic material (e.g., peat moss,
straw), chemical treatment, additional disking of the soil or soil and
absorbent material removal if the soil and/or absorbent material within the
spill area cannot meet the TPH standard specified in sub-paragraph (c)(4)(C)
above.
I) Contaminated soils
removed from the site for off-site disposal shall be disposed of at an Arkansas
Department of Environmental Quality permitted landfill permitted to receive
such waste other ADEQ 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 sub-paragraph (c)(4)(I) above; or
B) incorporated into the non-road ditch area
of the spill and remediated in accordance with sub-paragraph (c)(4)(A) thru (E)
above.
6) The Permit
Holder shall be required to submit on request, or within 15 days after the
spill occurred, on a form prescribed by the Director, the following
information:
A) a topographic map showing the
areal extent of the spill and the proximity of surface waters;
B) the type of soil and current land
use;
C) the TPH content in the
spill area;
D) explanation of the
cause of the spill, and planned efforts to prevent and minimize the effects of
future spills at the site.
E)
Additional reports are required each 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 rule, from wells, flowlines, pits,
tanks or containment dikes, shall immediately, but not more than 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 50 lbs. of agricultural grade lime per 100 square feet of affected area
and tilled to a depth of at least 4 inches.
4) 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. These additional actions may include flushing of
the area with freshwater (which shall be collected and disposed in a permitted
Class II well), the addition of organic material (e.g., peat moss, hay, straw),
additional chemical treatment, additional disking the soil, or soil removal.
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.
(Source: 1992 rule book; amended September 17, 2007)
RULE B-35:
DETERMINING AND NAMING COMMON SOURCES OF
SUPPLY
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 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.
In naming the common sources of supply, preference shall be given
to common usage and geographical names. Separate common sources of supply
within the same area shall preferably be named according to the producing
formation.
(Source: 1992 rule book)
RULE B-36:
TAKINGS TO BE
RATABLE
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 producer against another, or in favor of
any one source of supply as against another. 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 Rule A-4 and
takings shall be deemed to be ratable when purchases are made without
discrimination between wells within each such separate classification.
(Source: 1992 rule book)
RULE B-37:
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 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:
1) That each well dually completed shall be
regarded as a separate and distinct Well; and
2) That the production shall be taken and
measured separately; and
3) That
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 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 proof of written notice to
all offset operators or owners, as defined in Ark. Code Ann. §
15-72-109,
in governmental sections that are contiguous to the lease upon which
uncontrolled gas is to be produced; or if controlled, then proof to all offset
operators or owners, as defined in Ark. Code Ann. §
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 of as required
by General Rule B-15; and
3) The
proposed zone to be produced would otherwise not be economic due to limited
production potential.
4) Any offset
operator or owner noticed in accordance with subparagraph (b)(1) above shall
have the right to object to the granting of such application within fifteen
(15) days after receipt of the application by the Commission.
5) 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 this paragraph (b), the application
shall be denied. 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.
6) 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
this paragraph (b), the application shall be approved.
(Source: 1992 rule book; amended December 16, 2007)
RULE B-38:
ESTABLISHMENT OF FIELD RULES
a) 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 General Rule
B-43 or General Rule B-44, shall be submitted, in accordance with General Rules
A-2, A-3, and applicable hearing procedures, to the Commission within six
months after the initial completion of the discovery well in a pool or
reservoir or after the drilling of three wells, whichever occurs first. Prior
to receipt of an application, no further permits to drill more than three wells
in the same source of supply in the exploratory area as defined by the Director
shall be issued.
b) 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 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. 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 General Rule A-2, A-3 and other applicable hearing
procedures, grant exceptions to this rule, provided such exceptions will create
neither waste nor hazards conducive to waste.
(Source: 1992 rule book; amended September 16, 2006; amended
August 17, 2008)
RULE
B-39:
REPEALED
Rule Repealed Effective October 19, 2018 in accordance with Act
781 of 2017
RULE
B-40:AUTHORIZATION FOR DIRECTOR OF PRODUCTION
AND CONSERVATION TO ADMINISTRATIVELY APPROVE APPLICATIONS FOR EXCEPTIONAL WELL
LOCATIONS
a) The Director
of Production and Conservation or his 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 Commission general
rules. This rule is only applicable:
(1) To
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 General Rule B-3,
or for dry gas wells drilled in Exploratory Units established by Commission
order; or
(2) To 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
(3) To oil wells located in uncontrolled
fields where the standard well setback as specified in General Rule B-3, apply
to lease lines rather than drilling unit lines.
b) 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 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 the 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. If the proposed location encroaches upon more than one 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 sub section
1) below.
1) If the proposed location
encroaches upon more than one boundary as specified in section (b) 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)
2) Each
such application for an exceptional location shall be submitted on a form
prescribed by the Director of Production and Conservation, accompanied by an
application fee of $500.00 and include the name and address of each owner, as
defined in A.C.A. §
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(s), which shall be encroached upon by the proposed
exceptional well location.
3)
Concurrently with the filing of an application in accordance with this rule,
the applicant shall send to each owner specified in sub-section 2) 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(s) of mailing.
4) Any owner noticed in accordance with
sub-section 2) 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. Each objection must be made in writing and filed with the
Director. 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. If the application is denied under this
subsection, the applicant may request to have the application placed, in
accordance with General Rule A-2, A-3, 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.
5) An application may be referred to the
Commission for determination when the Director:
(1) deems 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 A.C.A. §
15-72-102(8),
by reason of the drilling of the well at such exceptional location, or
(2) deems it necessary that the
Commission make such determination for the purpose of protecting correlative
rights of all parties. 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(s) for denial of the application
under this rule and the referral to the full Commission for
determination.
6)
Applications for exceptional locations resulting from directional drilling
shall be considered for administrative approval in accordance with this rule,
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. In all such cases where directional surveys
are made available, the distance of the midpoint perforations, for each common
source of supply in a directional well, from the drilling unit boundary shall
be used in calculating the allowable.
7) If the Director has not notified the
applicant of the determination to refer the application to the Commission
within the fifteen (15) 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 sub-section 4), the application shall be
approved and a Drilling Permit issued.
c) For dry gas wells, as specified in
sub-section a) 1) above, an alternative to a reduction in the allowable
(penalty) method, as outlines in Section b) above, may be requested if each
affected drilling unit has been previously integrated, by Commission Order or
is 100% leased, and is currently held by production, and if 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. 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 designee. The method for
determining the percentages for sharing the costs of and the proceeds of
production from one or more separately metered wells shall be as follows:
1) For vertical or directionally drilled
wells, the acreage within an agreed upon area extending out from the perforated
internal, as defined in General Rule B-3, shall be calculated for each such
separately metered well (the "calculated area"). The calculated area shall be
based upon the estimated drainage area of the perforated interval.
2) 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.
3) Each such application for utilizing the
above methodology shall be submitted on a form prescribed by the Director of
Production and Conservation, accompanied by an application fee of $500.00 and
include the name and address of each owner, as defined in A.C.A. §
15-72-102(9),
within each of the drilling units in which the proposed well is to be drilled
and/or completed and which contains a portion of the calculated area as defined
in sub-section c) 1) above.
Concurrently with the filing of an application utilizing the
above methodology, the applicant shall send in written authorization from each
owner specified in sub-section c) 3) above.
5) 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. 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(s) for denial of the application
under this rule and the referral to the full Commission for
determination.
6) If the Director
has not notified the applicant of the determination to refer the application to
the Commission within the fifteen (15) 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 subsection (c)(5),
the application shall be approved and a drilling permit issued.
7) Upon receipt of the drilling permit, the
applicant shall give the other working interest parties written notice that the
drilling permit has been issued. 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 non-consent and subject to the non-consent penalty set out in the
existing Joint Operating Agreement(s) covering their respective drilling
unit.
8) 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
sub-section c) 1) above.
(Source: 1992 rule book; amended (Order 1-94(4)) January 25,
1994; amended July 17, 2006; amended December 16, 2007; amended August 17,
2008)
RULE
B-41:
RULE FOR OPERATION IN HYDROGEN SULFIDE
(H2S) AREAS
Each operator who conducts operations in known areas of Hydrogen
Sulfide (H2S) with minimum concentrations of fifteen
(15) ppm under atmospheric conditions or one hundred (100) ppm or more in the
gas stream shall provide safeguards to protect the general public from the
harmful effects of Hydrogen Sulfide (H2S). The Director
of the Arkansas Oil and Gas Commission shall determine the areas covered by
this rule.
Operations shall include drilling, completion, workover,
producing, gathering, and storage of hydrocarbon fluids, natural gas and fluids
produced in association with Bromine extraction. 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.
DEFINITIONS
Radius of Exposure shall
mean that radius constructed with the point of escape as its starting point and
its length calculated as provided for in General Provisions D.
Area of Exposure shall mean
the area within a circle constructed with the point of escape as its center and
the radius of exposure as its radius.
Public Area shall mean 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.
Public Road shall mean any
federal, state, county, or municipal street or road owned or maintained for
public access or use.
Contingency Plan shall mean
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.
I.
GENERAL
PROVISIONSA. Each
operator shall determine the Hydrogen Sulfide (H2S)
concentration in the gaseous mixture in an operation or system. Test of vapor
accumulation in storage tanks may be made with industry accepted colormetric
tubes.
B. Each operator shall
immediately notify the Arkansas Oil and Gas Commission of any accidental
release of Hydrogen Sulfide (H2S) gas which measures 15
ppm or greater from any point on a radius which exceeds 100 feet from the point
of release, or includes any portion of a public area. Such notification shall
be followed by a written report which shall be sent to the Commission within
ten (10) days of the incident.
C.
Each operator shall notify the AOGC before conducting any well servicing
activity on any well(s) operated under the provisions of this rule.
D. For all operations subject to a radius of
exposure (ROE), that radius shall be determined by the following
Pasquill-Gifford Equations
1. 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.
For drilling of a well where insufficient data exist to calculate
a ROE, but where Hydrogen Sulfide may be expected, then a radius of exposure
shall be three thousand (3000) feet. A lesser -assumed radius may be considered
upon written request setting out the justification for same.
E. 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.
II.
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 100 ppm, shall be subject to the following:
A. No determination of a radius of exposure
shall be made for storage tanks as herein described.
B. A warning sign shall be posted on or
within fifty (50) feet of the facility to alert the general public of the
potential danger.
C. All tank
hatches shall be kept closed at all times except for when it is necessary to
inspect or gauge such tanks. All storage tanks that are not fenced as required
in (D.) below are required to be kept secured by lock the hatches on all such
tanks when not being inspected or gauged.
D. Entry should be restricted to essential
personnel only. 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. All means of entry shall be locked when the facility is
unattended.
E. All 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. Permits to vent will be reviewed with respect to the
distance to the nearest public receptor, the concentration of H2S gas and the
volume to be released.
III.
WARNING AND MARKER
PROVISIONA. A warning
sign shall be maintained on all streets or roads which provide access to the
facility.
B. 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.
C. 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.
D. In satisfying the sign
requirement, the following will be acceptable:
1. Sign of sufficient size to be readable at
a reasonable distance from the facility.
2. Existing signs installed prior to the
effective date of this section will be acceptable if they indicate the
existence of a potential hazard.
IV.
CONTROL AND EQUIPMENT
SAFETY PROVISION
Operators subject to this provision shall install safety devices
and maintain them in an operable condition and shall establish safety
procedures designed to prevent the undetected continuing escape of Hydrogen
Sulfide (H2S). Safety devices should be tested annually
and a record of each test maintained.
V.
DRILLING AND WORKOVER
PROVISIONSA. 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.
B. Drilling operations are
required to be in compliance with the provisions of the rule when the drilled
depth is within 1,000 feet of a zone known to or that may contain Hydrogen
Sulfide. A variance from the compliance depth may be approved upon written
request setting out justification, however the compliance depth will not be
less than 500 feet.
C. Protective
breathing equipment shall be maintained for all personnel at the
site.
D. 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.
E. Blowout preventers and
well control systems shall be pressure tested initially either to a minimum of
3,000 psig or to 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. Thereafter, all well control systems shall be tested prior to reaching
compliance depth. The Oil and Gas Commission shall be notified at least four
(4) hours prior to the initial "Blowout Preventer and Well Control System
Test". The Commission shall have the authority to vary test procedures as is
deemed necessary.
F. Secondary
remote control of blowout prevention and choke equipment shall be located away
from the rig floor at a safe distance from the wellhead.
G. The operator shall install a choke
manifold, mud-gas separator and flare line, and provide a suitable method for
lighting the flare.
H. Drill Stem
Testing:
1. Drill stem testing of Hydrogen
Sulfide (H2S) zones is permitted only in daylight
hours.
2. The Oil and Gas
Commission shall be notified a minimum of 12 hours in advance of the intention
to conduct a drill stem test of a formation containing Hydrogen Sulfide
(H2S). 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.
3. All gas
produced from the test shall be flared through a flare system with a pilot and
an automatic igniter.
4. Every
precaution should be made not to affect the public during the well test. In the
event, 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. Special consideration should be given residents with
children and/or medical ailments.
I. 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.
J. API Publication RP-49 and RP-68 is
referenced as a suggested guideline for drilling and workover of wells subject
to the provision.
VI.
CONTINGENCY PLAN PROVISION
A. 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.
B. 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).
C. The contingency plan shall be activated
immediately upon the detection of an accidental release of Hydrogen Sulfide
(H2S) which exceeds fifteen (15) ppm or greater from any
point on a radius which exceeds 100 feet from the point of release, or includes
any portion of a public area.
D.
Conditions that might exist in each area of exposure shall be considered when
preparing a contingency plan.
E.
The plan shall include instructions and procedures for alerting the general
public and public safety personnel of the existence of an emergency.
F. The plan shall include a procedure for
requesting assistance and for follow-up action to evacuate the public from an
area of exposure.
G. The plan shall
include a call list which will include the following as they may be applicable:
1. Local supervisory personnel
2. Arkansas Oil and Gas Commission
3. County Sheriff
4. State Police
5. Ambulance Service
6. Hospital
7. Fire Department
8. Contractors for supplemental
equipment
9. Office of Emergency
Services
10. Other public agencies
as needed
H. The plan
shall include a plat detailing the area of exposure. 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. A separate
list of all phone numbers should be attached to the plat.
I. A schematic of the facility indicating all
equipment on location should be included.
J. The Oil and Gas Commission shall be
notified immediately if the contingency plan is activated.
K. The retention of the contingency plan
shall be as follows:
1. The plan shall be
available for Commission inspection at the well location.
2. The plan shall be retained at the location
which lends itself best to activation of the plan.
L. The plan shall be kept updated to insure
its current applicability. 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.
VII.
TRAINING PROVISION
Each operator and contractor shall provide appropriate Hydrogen
Sulfide (H2S) training for its employees who will be
on-site. All personnel must have in their possession, current proof of annual
training. This training should include the following:
1. Hazards and characteristics of Hydrogen
Sulfide (H2S).
2. Operations of safety equipment and life
support systems.
3. First aid in
the event of an employee exposure.
4. Use and operation of Hydrogen Sulfide
(H2S) monitoring equipment.
5. Emergency response procedures to include
corrective actions, shutdown procedures, evacuation routes and rescue methods.
(Source: 1992 rule book)
RULE B-42:
SEISMIC
RULES
(a) Definitions:
1. "Field Seismic Operations" shall mean 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 preliminary line survey, the
acquisition of necessary permits, the selection and marking of shot-hole
locations, necessary clearing of vegetation, shot-hole drilling, implantation
of charge, placement of geophones, detonation and backfill of
shot-holes.
2. "Seismic Shoot"
shall mean 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) Any person desiring to perform
field seismic operations within the State of Arkansas shall obtain a permit for
each seismic shoot from the Commission prior to commencing field seismic
operations. A copy of the approved permit shall be maintained in the central
recording unit used for the seismic shoot. Such permit shall be valid for a
period of one year from the date of issuance.
(c) The applicant shall make application on a
form prescribed by the Director.
(d) Each application as filed shall be
accompanied by an application fee of Five Hundred Dollars ($500.00).
(e) Each application for a 2D seismic shoot
shall include information and maps,
(i) to
identify the seismic shoot area,
(ii) to indicate the proposed location of all
2D seismic lines, and
(iii) to
designate an area (each, a "2D Seismic Line Corridor" within which a 2D seismic
line may be located or relocated by permitee). 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. Applicants may omit areas
within the outer boundaries of any 2D Seismic Line Corridor from the 2D Seismic
Line Corridor. 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. 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. The applicant shall also be required to file an amended application
showing the revised location of such relocated 2D seismic lines, if applicable.
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.
Subject to any applicable exceptions, including without limitation the trade
secret exception to the general requirements of Ark. Code Ann. (1987) §
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. 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 object to their admissibility and to seek a closed hearing or a protective
order with respect thereto.
(f) The application shall be accompanied with
evidence of the appropriate type(s) of financial assurance, as described in
General Rule B-2 (d)(1), (2), (3) and (4), and subject to those conditions
listed therein.
1. 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 Rule shall not exceed two hundred fifty
thousand dollars ($250,000).
2. 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.
3. The financial assurance required to be
filed shall remain in effect for one year following the conclusion of all field
seismic operations by the permit holder in the State of Arkansas.
(g) Upon review of a completed
permit application, the Director shall either issue the permit or deny the
permit application. If the permit application is denied, the applicant may file
an application for a hearing to appeal the Director's decision in accordance
with General Rule A-2, A-3, and other applicable hearing procedures.
(h) 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.
1. The notice shall be in writing
and given either personally or by certified United States mail 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
2. 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. Any such notice to an occupant shall be deemed delivered if delivered
personally or deposited in the United States mail postage prepaid to said
occupants at the mailing address of the lands.
3. Written notice shall also be given either
personally or by certified United States mail to operators, as reflected in the
records of the AOGC, of producing wells within the seismic shoot area, at the
mailing addresses identified for such operators in said records.
4. 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
C. Approximate date
the person or entity proposes to commence field seismic operations;
(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 (3) inches in
height and one-half (1/2) inch wide, indicating the name of such
agent.
(k) 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(s)
thereof and the permit holder shall be responsible for any resulting damages in
accordance with this rule. Written authority must also be obtained from the
owner(s) if any charge exceeds the maximum allowable charge within the scaled
distance below:
DISTANCE TO STRUCTURE (FT)*
|
MAXIMUM ALLOWABLE CHARGE 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 (lbs.) is 25.0, unless the permit holder requests and
secures the prior written authorization from the Director.
(m) All holes drilled for field seismic
activity shall be properly back filled with soils and/or other suitable
material and tamped. A mound may be left over the hole for settling
allowance.
(n) 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. The cap leads for any seismic
sources that fail to detonate shall be buried at least three (3) feet
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) Unless otherwise consented to by the
surface owner in writing, permit holder shall not cut down any tree measuring
six (6) inches or more in diameter, as measured at a height of three (3) feet
from the ground surface unless there are no reasonable alternatives to the
removal of such tree(s) available to permit holder. 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) 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. Any person who does not
fully comply with any other provision of this rule 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 rule or Ark. Code Ann. (1987) §
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 subparagraph (t)
above.
(v) In addition, any surface
owner may seek to recover damages from the financial assurance, as follows:
1. 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;
provided however, that such claim shall be subordinate to the rights of the
Commission.
2. Any claim received
from a surface owner shall be investigated by the Director and a decision shall
be rendered by the Director. 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
General Rule A-2, A-3, and other applicable hearing procedures. At a hearing,
the surface owner must prove that
(a) actual
damages occurred,
(b) such damages
were caused by
(i) the negligence of the
permit holder,
(ii) a violation of
this rule by permit holder or
(iii) 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
(c) the amount of such
damages.
3. If the
Commission finds that the permit holder is liable to the surface owner for any
such damages, the permit holder shall have 30 days from the effective date of
the order to pay the surface owner the amount specified by the Commission. 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 General Rule B-2 (k) to pay damages specified by the Commission,
provided however, that such amount shall be subordinate to the rights of the
Commission.
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.
(Source: 1992 rule book; amended July 3, 2003; amended June 15,
2008)
RULE
B-43:
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 rule, unconventional
sources of supply shall mean 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 rule, conventional
sources of supply shall mean all common sources of supply that are not defined
as unconventional sources of supply in section (a) above.
(c) This rule 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 "section (c) lands". The development of the
conventional and unconventional sources of supply within the section (c) lands
shall be subject to the provisions of this rule.
(d) This rule is further applicable to all
occurrences of unconventional sources of supply in Crawford, Franklin, Johnson,
and Pope Counties, Arkansas and shall be called the "section (d) lands". The
development of the unconventional sources of supply within the section (d)
lands shall be subject to the provisions of this rule. For purposes of this
rule, the section (d) lands and the section (c) lands may collectively be
referred to as the "covered lands".
(e) All Commission approved Fayetteville
Shale and non-Fayetteville Shale fields that are situated within the section
(c) lands and that are in existence on the date this rule is adopted
(collectively, the "existing fields"), are abolished and the lands heretofore
included within the existing fields are included within the section (c) lands
governed by this rule. Further, all amendments that added the Fayetteville
Shale Formation to previously established fields for conventional sources of
supply occurring in the section (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 rule. All
existing individual drilling units however, contained within the abolished
fields shall remain intact.
(f) All
drilling units established for conventional and unconventional sources of
supply within the section (c) lands and all drilling units established for
unconventional sources of supply within the section (d) lands shall be
comprised of single governmental sections, typically containing an area of
approximately 640 acres in size. Each drilling unit shall be characterized as
either an "exploratory drilling unit" or an "established drilling unit". An
"exploratory drilling unit" shall be defined as any drilling unit that is not
an established drilling unit. An "established drilling unit" shall be defined
as 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 filed, with the Commission, all appropriate documents in
accordance with General Rule B-5, and been issued a certificate of compliance.
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) The
filing of an application to integrate separately owned tracts within an
exploratory drilling unit, as defined in Section (f) above and as contemplated
by A.C.A. §
15-72-302(e),
is permissible, provided that one 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. 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:
1) 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. 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.
2) If any non-applicant
working interest owner in the drilling unit owns, or has the written support of
one or more working interest owners that own, separately or together, at least
a fifty percent (50%) working interest in the drilling unit, such non-applicant
working interest owner may (i) object to the applicant being named operator (a
"section (g) operator challenge") or (ii) file a competing integration
application (a "section (g) competing application") that challenges any aspect
of the original integration application for such drilling unit. Any contested
matter that is limited to a section (g) operator challenge shall be heard at
the Commission hearing that was originally scheduled for such integration
application. Any contested matter that involves the filing of a section (g)
competing application shall be postponed until the next month's regularly
scheduled Commission hearing if postponement is requested by either competing
applicant.
3) 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.
4) In the event two parties desiring to be
named operator own, or have the written support of one or more working interest
owners that own, exactly, an undivided 50% share of the drilling unit and
either a section (g) operator challenge is submitted or a section (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.
5) If the person designated as operator by
the Commission in the adjudication of a section (g) operator challenge or a
section (g) competing application does not commence actual drilling operations
on the drilling unit within the twelve (12) 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) The filing
of an application to integrate separately owned tracts within an established
drilling unit, as defined in Section (f) above and as contemplated by A.C.A.
§
15-72-303
is permissible, without a minimum acreage requirement, provided that one 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. 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:
1) 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. 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.
2) Any non-applicant working
interest owner in the drilling unit may object to the applicant being named
operator (a "section (h) operator challenge"). In addition, if an objecting
party owns, or has the written support of one 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 "section (h) competing application") that challenges
any aspect of the original integration application for such drilling unit. Any
contested matter that is limited to a section (h) operator challenge shall be
heard at the Commission hearing that was originally scheduled for such
integration application. Any contested matter that involves the filing of a
section (h) competing application shall be postponed until the next month's
regularly scheduled Commission hearing if postponement is requested by either
competing applicant.
3) If a party
desiring to be named operator of a drilling unit is a majority owner (as
defined in subsection (g)(3) above), the majority owner shall be designated
unit operator.
4) 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. If a section (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 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.
5) If two or more parties that desire to be
named operator own, or have the support of one 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.
6) If the person designated as operator by
the Commission in the adjudication of a section (h) operator challenge or a
section (h) competing application does not commence actual drilling operations
on the drilling unit within the twelve (12) 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 Section
(a)(2) of General Rule B-3) shall be at least 560 feet from any drilling unit
boundary line, unless an exception is granted by the Commission after notice
and hearing in accordance with General Rules A-2 and A-3, and other applicable
hearing requirements, or in accordance with paragraph (o) below;
2) The perforated interval of the wellbore
shall be at least 560 feet 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 an exception is granted in accordance with
subparagraph (i)5) below);
3) The
perforated interval of the wellbore shall be at least 448 feet in any
direction, an allowed 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 subparagraph (i)5)
below);
4) No more than 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 General Rules A-2 and
A-3, and other applicable hearing requirements. For purposes of this subsection
only, a well is any vertical well, directional well, horizontal well with at a
minimum 560 feet of perforated interval in the drilling unit, or if a
horizontal does not contain a minimum of 560 feet of perforated lateral in any
one 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 or his designee is authorized
to approve an application requesting an exception to subsection (i)2) and/or
(i)3) administratively, if the following conditions are met:
A. Each such application shall be submitted
on a form prescribed by the Director of Production and Conservation, and
include the name and address of each owner, as defined in Ark. Code Ann. (1987)
§
15-72-102(9),
within each of the drilling units in which the proposed well is to be drilled
and/or completed.
B. Concurrently
with the filing of the application for an exceptional location in accordance
with subsection (i)2) and or (i)3) above, the applicant shall send to all
owners, as defined in Ark. Code Ann. (1987) §
15-72-102(9),
whose mailing addresses may reasonably be ascertained, in all affected units, 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(s) of mailing.
Additionally, if there are any owners, as defined in Ark. Code Ann. (1987)
§
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 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. Any owner, as
defined in Ark. Code Ann. (1987) §
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. Each objection must be made in writing and filed with the Director.
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. 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 General Rules A-2 and A-3, 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.
E. 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.
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(s) for referral to the full Commission for
determination. If the application is referred under this section, the applicant
shall file a request for a hearing, in accordance with General Rules A-2 and
A-3, and other applicable hearing requirements, except that no additional
filing fee is required.
F. 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 (15) 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 subsection (i)5)C. above, the
application shall be approved and a permit issued.
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 section (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 General Rule D-19;
2) Each well location (as defined in Section
(a) 2) of General Rule B-3) shall be at least 1120 feet from any drilling unit
boundary line;
3) Well completions
located closer than 1120 feet from all established drilling unit boundaries,
shall be subject to approval in accordance with General Rule B-40;
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 rule and occurring in the covered lands specified by
this rule shall be in accordance with General Rule B-15.
(l) Wells completed in and producing from
only conventional sources of supply, as defined in Section (b), shall be
subject to the testing provisions of General Rule D-16 and production allowable
provisions of General Rule D-21. Wells completed in and producing from only
unconventional sources of supply, as defined in Section (a), shall not be
subject to the testing provisions of General Rule D-16 and allowable provisions
of General Rule D-21 There shall be no production allowable established for
wells producing from unconventional sources of supply located within the
covered lands. 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 (24) 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) 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 General Rule D-18. 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 General Rule D-21.
(n) The reporting requirements of General
Rule B-5 shall apply to all wells subject to the provisions of this rule. In
addition, the operator of each such well shall be required to file monthly gas
production reports in accordance with General Rule D-8.
(o) The Commission specifically retains
jurisdiction to consider applications brought before the Commission from a
majority in interest of all owners, as defined by Ark. Code Ann. (1987) §
15-72-102(9),
in two or more adjoining drilling units seeking the authority to drill, produce
and/or share the costs of and the proceeds of production from one or more
separately metered wells that extend across or encroach upon drilling unit
boundaries and that are drilled and completed in one or more unconventional
sources of supply within the covered lands. All such applications shall contain
a proposed agreement on the formula for the sharing of costs, production and
royalty from the affected drilling units.
1)
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.
2) Administrative Approval of Wells that
Extend Across or Encroach Upon Drilling Unit Boundaries. If the majority in
interest of all owners, as defined by Ark. Code Ann. (1987) §
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 or more adjoining drilling units which are all
integrated or are 100% leased utilizing the below methodology for sharing of
costs, production and royalty among the affected drilling units, the Director
or his designee is authorized to approve the application administratively, if
the following conditions are met:
A. The
application provides proof that:
i) There is
at least one well located, as defined in subsection (a)(2) of General Rule B-3,
at a non-exceptional well location and located entirely within each included
drilling unit that is producing or capable of producing gas; or ii) Within
twelve (12) months following the date the well for which administrative
approval is granted is spud, there will be at least one well located, as
defined in subsection (a)(2) of General Rule B-3, at a non- exceptional 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; or iii) There is at least one well or a
combination of multiple wells, including cross unit wells and/or encroaching
wells located, as defined in subsection (a)(2) of General Rule B-3, within each
included drilling unit that have a total combined perforated lateral length
within the drilling unit of not less than 4160 feet, and are producing or are
capable of producing gas; or iv) Within twelve (12) months following the date
the well for which administrative approval is granted is spud, there will be at
least one well or a combination of multiple wells, including cross unit wells
and or encroaching wells located, as defined in subsection (a)(2) of General
Rule B-3, within each included drilling unit that have a total combined
perforated lateral length within the drilling unit of not less than 4160 feet,
and are producing or are capable of producing gas and awaiting connection to a
pipeline; or v) At least seventy five percent (75%) of the fee mineral
ownership within each included drilling unit that does not contain one or more
wells satisfying the requirements of subpart 2)A.i) or subpart 2)A. iii) above
agree in writing to the well; and
B. Notice has been given to all owners, as
defined by Ark. Code Ann. (1987) §
15-72-102(9)
and no objections were received by the Director in accordance with subsection
2) I) below; and
C. The application
includes detailed plat maps indicating current well locations and potential
future well development plans in all included drilling units.
D. If administrative approval is granted,
based upon either or both of subsection 2)A.ii) or iv) above, and the applicant
fails to satisfy one of the conditions specified in subsection 2)A.ii) or iv)
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 General Rule A-2, A-3, and other applicable
hearing procedures prior to the expiration of the time period specified in such
subsections, or the Commission otherwise approves the application.
E. The method for sharing the costs of and
the proceeds of production from one or more separately metered wells shall be
based on acreage allocation as follows:
i) An
area measured 560 feet along and on both sides of the entire length of the
horizontal perforated section of the well, and including an area formed by a
560 feet radius from the beginning point of the perforated interval, and a 560
feet radius from the ending point of the perforated interval shall be
calculated for each such separately metered well (the "calculated area").
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.
F. Each such application for utilizing the
above methodology shall be submitted on a form prescribed by the Director of
Production and Conservation, accompanied by an application fee of $500.00 and
include the name and address of each owner, as defined in Ark. Code Ann. (1987)
§
15-72-102(9),
within each of the drilling units in which the proposed well is to be drilled
and/or completed.
G. Concurrently
with the filing of an application utilizing the above methodology, the
applicant shall send to each owner specified in subsection 2)F. 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 Ark. Code Ann. (1987) §
15-72-102(9),
and the date(s) of mailing.
H. Any
owner, as defined by Ark. Code Ann. (1987) §
15-72-102(9),
noticed in accordance with subsection 2) G) 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. Each objection must be made in
writing and filed with the Director. 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. 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 General Rules A-2 and A-3, and other
applicable hearing requirements, except that no additional filing fee is
required.
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. 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(s) for referral to the full Commission for determination. If the
application is referred under this section, the applicant shall file a request
for a hearing, in accordance with General Rules A-2 and A-3, and other
applicable hearing requirements, except that no additional filing fee is
required.
J. If the
Director has not notified the applicant of the determination to refer the
application to the Commission within the fifteen (15) 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 subsection 2)I,
the application shall be approved and a drilling permit issued.
K. Upon receipt of the drilling permit, the
applicant shall give the other owners, as defined by Ark. Code Ann. (1987)
§
15-72-102(9),
written notice that the drilling permit has been issued. The owners, as defined
by Ark. Code Ann. (1987) §
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 non-consent and subject to the non-consent
penalty set out in the existing Joint Operating Agreement(s) covering their
respective drilling unit or units.
L. 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 subsection 2) E) above.
3) 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 Director and in the real
estate property records in all counties where any portion of the drilling units
are located.
(p) The
Commission shall retain jurisdiction to consider applications, brought before
the Commission, from a majority in interest of working interest owners in two
or more adjoining governmental sections seeking the authority to combine such
adjoining governmental sections into one drilling unit for the purpose of
developing one or more unconventional sources of supply. In any such
multi-section 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.
(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)
RULE B-44:
ESTABLISHMENT OF DRILLING UNITS FOR GAS PRODUCTION FROM ALL
SOURCES OF SUPPLY OCCURING IN CERTAIN PRODUCING AREAS IN FRANKLIN, LOGAN,
SCOTT, SEBASTIAN AND YELL COUNTIES
(a) Definitions:
(1) "Unconventional Sources of Supply" shall
mean 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.
(2)
"Conventional Sources of Supply" shall mean all common sources of supply that
are not defined as unconventional sources of supply in section (a)(1) above or
the Middle Atoka as defined in section (a)(4) below, or a tight gas formation
as defined in section (a) (3) below.
(3) "Tight Gas Formation" shall mean tight
gas formation as defined in Ark. Code Ann. (1987) §
26-58-101.
(4) "Middle Atoka" shall mean 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 section (b) below.
(b) This rule is applicable to all sources of
supply occurring in the "covered lands," except the Hartshorne Coal Formation
or any other coal formation. The development of these sources of supply within
the covered lands shall be subject to the provisions of this rule. The covered
lands are specified as follows:
(1) Sections
19-36, T7N R28W; Sections 1-3 and 11, T6N, R29W all in Franklin
County;
(2) 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;
(3) 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;
(4) 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;
(5) All of T5N
R25W; all of T5N R24W; all of T5N R23W; all of T4N R25W; all of T4N R24W; 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;
(6) After notice and
hearing, the 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) 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 rule 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 rule. 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. All existing individual
drilling units however, contained within the abolished fields shall remain
intact.
(e) 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
640 acres in size, unless a different size and/or configuration is approved for
any unit or units by Order of the Commission. Each drilling unit shall be
characterized as either an "exploratory drilling unit" or an "established
drilling unit". An "exploratory drilling unit" shall be defined as any drilling
unit that is not an established drilling unit. An "established drilling unit"
shall be defined as any drilling unit that contains a well that has been
drilled and completed in any source of supply (a "subject well"), and for which
the operator or other person responsible for the conduct of the drilling
operation has filed, with the Commission, all appropriate documents in
accordance with General Rule B-5, and has been issued a certificate of
compliance. 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. All existing "exploratory drilling units"
contiguously located to drilling units with established production at the time
this rule is adopted, shall be automatically reclassified as established
drilling units.
(f) The filing of
an application to integrate separately owned tracts within an exploratory
drilling unit, as defined in Section (e) above and as contemplated by A.C.A.
§
15-72-302(e),
is permissible, provided that one 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.
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:
1) 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. 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.
2) If any non-applicant working interest
owner in the drilling unit owns, or has the written support of one or more
working interest owners that own, separately or together, at least a fifty
percent (50%) working interest in the drilling unit, such non-applicant working
interest owner may
(i) object to the applicant
being named operator (a "section (f) operator challenge") or
(ii) file a competing integration application
(a "section (f) competing application") that challenges any aspect of the
original integration application for such drilling unit. Any contested matter
that is limited to a section (f) operator challenge shall be heard at the
Commission hearing that was originally scheduled for such integration
application. Any contested matter that involves the filing of a section (f)
competing application shall be postponed until the next month's regularly
scheduled Commission hearing if postponement is requested by either competing
applicant.
3) 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.
4) In the event two
parties desiring to be named operator own, or have the written support of one
or more working interest owners that own, exactly, an undivided 50% share of
the drilling unit and either a section (f) operator challenge is submitted or a
section (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.
5) If the person designated as operator by
the Commission in the adjudication of a section (f) operator challenge or a
section (f) competing application does not commence actual drilling operations
on the drilling unit within the twelve (12) 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, (ii) a majority-in-interest of the total working interest ownership in
the drilling unit (excluding such designated operator) support such operator.
(g) The filing of an
application to integrate separately owned tracts within an established drilling
unit, as defined in Section (e) above and as contemplated by A.C.A. §
15-72-303
is permissible, without a minimum acreage requirement, provided that one 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. 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:
1) 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. 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.
2) Any non-applicant working
interest owner in the drilling unit may object to the applicant being named
operator (a "section (g) operator challenge"). In addition, if an objecting
party owns, or has the written support of one 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 "section (g) competing application") that challenges
any aspect of the original integration application for such drilling unit. Any
contested matter that is limited to a section (g) operator challenge shall be
heard at the Commission hearing that was originally scheduled for such
integration application. Any contested matter that involves the filing of a
section (g) competing application shall be postponed until the next month's
regularly scheduled Commission hearing if postponement is requested by either
competing applicant.
3) If a party
desiring to be named operator of a drilling unit is a majority owner (as
defined in subsection (f) (3) above), the majority owner shall be designated
unit operator.
4) 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. If a section (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 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.
5) If two or more parties that desire to be
named operator own, or have the support of one 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.
6) If the person designated as operator by
the Commission in the adjudication of a section (g) operator challenge or a
section (g) competing application does not commence actual drilling operations
on the drilling unit within the twelve (12) 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, (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 General
Rule B-3 (a)(2), shall be at least 560 feet from any drilling unit boundary
line, unless an exception is approved in accordance with subparagraph (p) below
or in accordance with General Rule B-40;
2) Each well location, as defined in General
Rule B-3 (a)(2), shall be at least 560 feet from other well locations within an
established drilling unit, within common sources of supply, unless an exception
to this rule 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:
1) Each well
location, as defined in General Rule B-3 (a)(2), shall be at least 560 feet
from any drilling unit boundary line, unless an exception is approved in
accordance with subparagraph (p) below or in accordance with General Rule
B-40;
2) Each well location, as
defined in General Rule B-3 (a)(2) shall be at least 560 feet from other well
locations within an established drilling unit, unless the common sources of
supply are stratigraphically different named intervals, approved in accordance
with subparagraph (i) (3) below, or an exception to this rule is approved by
the Commission, following notice and hearing.
3) Application for approval of well locations
less than 560 feet 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, and contain, at a
minimum, the following information:
A) The
location of the unit;
B) The
location or proposed location of all wells being encroached upon, showing the
productive zones in each well;
C) A
cross-section, containing the location or proposed location of all wells being
encroached upon, demonstrating the productive zone will be from
stratigraphically different named intervals;
D) In addition, each application shall
provide proof of written notice to all owners, as defined in Ark. Code Ann.
§
15-72-102(9),
in the subject unit;
E) 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.
F) Any owner noticed
in accordance with sub-paragraph i) 3) E) 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)
If an objection is not received within fifteen (15) days after the receipt of
the application, and that the productive zone will be from stratigraphically
different named intervals, the Director shall approve the
application.
H) If an objection is
received, or if the application does not satisfy the requirements of this Rule
and is denied by the Director, the Applicant may request to have the matter
placed, in accordance with General Rules A-2, A-3 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:
1)
Each well location, as defined in General Rule B-3 (a)(2), shall be at least
560 feet from any drilling unit boundary line, unless an exception is approved
in accordance with subparagraph (p) below or in accordance with General Rule
B-40;
2) Each well location, as
defined in General Rule B-3 (a)(2) shall be at least 560 feet from other well
locations within an established drilling unit, within common sources of supply,
unless an exception to this rule is approved by the Commission, following
notice and hearing.
(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 General Rule D-19;
2) Each well location, as defined in General
Rule B-3 (a)(2), shall be at least 1120 feet from any drilling unit boundary
line, unless an exception is approved in accordance with subparagraph (p) below
or General Rule B-40;
(l) The casing programs for all wells drilled
in exploratory and established drilling units established by this rule, and
occurring in the covered lands specified by this rule, shall be in accordance
with General Rule B- 15 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 General Rule D-16 and allowable provisions of General Rule D-21,
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 General Rule D-18.
(o) The reporting requirements of General
Rule B-5 shall apply to all wells subject to the provisions of this rule. 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 45 days
after the last day of each month.
(p) The Commission specifically retains
jurisdiction to consider applications brought before the Commission from a
majority in interest of working interest owners in two 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 or more sources of supply within the
covered lands. All such applications shall contain a proposed agreement on the
formula for the sharing of costs, production and royalty from the affected
drilling units.
1) However, if the majority in
interest of working interest owners agree to share a proposed well between two
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 rule, the Director or his 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 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) For horizontal wells, an area (equal to
the setback footage for that source of supply as specified in section (h), (i),
(j) or (k) 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
section (h), (i), (j) or (k) above) from the beginning point of the perforated
interval and from the ending point of the perforated interval. 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 section (h), (i), (j) or (k) above) extending around the
perforated interval as defined in General Rule B-3, shall be calculated for
each such separately metered well and referred to as the "calculated
area".
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.
2) Each such application for
utilizing the above methodology shall be submitted on a form prescribed by the
Director of Production and Conservation, accompanied by an application fee of
$500.00 and include the name and address of each owner, as defined in A.C.A.
§
15-72-102(9),
within each of the drilling units in which the proposed well is to be drilled
and/or completed.
3) Concurrently
with the filing of an application utilizing the above methodology, the
applicant shall send to each owner specified in subsection (p)(2) 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(s) of mailing.
4) Any owner noticed in accordance with
subsection (p)(3) 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. Each objection must be made in writing and filed with the
Director. 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. 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 applicable state laws and General Rules A-2 and A-3, except
that no additional filing fee is required.
5) 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. 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(s) for denial of the application
under this rule and the referral to the full Commission for determination, in
accordance with applicable state laws and General Rules A-2 and A-3.
6) If the Director has not notified the
applicant of the determination to refer the application to the Commission
within the fifteen (15) 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 subsection (p)(4), the application shall
be approved and a drilling permit issued.
7) Upon receipt of the drilling permit, the
applicant shall give the other working interest parties written notice that the
drilling permit has been issued. The working interest parties, who have not
previously made an election, shall have 15 days after receipt of said notice
within which to make an election to participate in the well or be deemed as
electing non-consent and subject to the non-consent penalty set out in the
existing Joint Operating Agreement(s) covering their respective drilling unit
or units.
8) 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 (p)(1) above.
(q) The Commission shall retain jurisdiction
to consider applications, brought before the Commission, from a majority in
interest of working interest owners in two or more adjoining governmental
sections seeking the authority to combine such adjoining governmental sections
into one drilling unit for the purpose of developing one or more unconventional
sources of supply. In any such multi-section 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.
(Source: new rule June 15, 2008; amended January 22, 2009;
amended August 01, 2014)
RULE
B-45:
ESTABLISHMENT OF WELL SET-BACK
REQUIREMENTS FOR DRY GAS PRODUCTION WELLS OCCURING IN ESTABLISHED FIELDS IN
CRAWFORD, FRANKLIN, JOHNSON, LOGAN, MADISON, POPE, SCOTT, YELL, SEBASTIAN AND
WASHINGTON COUNTIES
a)
Applicability
1) Except as provided in
subparagraph a) 2) below, this rule applies to all controlled sources of
supply, as defined in Ark Code Ann. §
15-71-107,
occurring within any existing field created by an order of the Commission
within Crawford, Franklin, Johnson, Logan, Madison, Pope, Scott, Yell,
Sebastian and Washington Counties.
2) This rule 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 rule;
C) Any
source of supply governed by General Rule B-43, or
D) Any source of supply governed by General
Rule B-44.
3) After
notice and hearing, the Commission shall retain jurisdiction to extend the
provisions of this rule to any new fields established by the
Commission.
4) This rule applies to
wells in which controlled and uncontrolled sources of supply are
commingled.
b)
Definitions
1) "Encroachment Footage" shall
mean 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.
2) "Existing PRU" shall mean
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 rule.
3) "FUB" shall mean distance from a drilling
unit boundary line.
4) "New PRU"
shall mean 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
rule.
5) "Penalty Allowable" shall
mean 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" shall
mean the factor which is multiplied by the New or Existing PRU to impose a
penalty (or reduction) upon the PRU Deliverability.
7) "PRU Deliverability" shall mean 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.
8) "Setback
Footage" shall mean the required minimum distance a New or Existing PRU must be
from the drilling unit boundary.
c) After the effective date of this rule, the
Setback Footage for all drilling units subject to this rule shall be as
follows:
1) For all existing drilling units
with a Setback Footage that is less than 660 feet, the Setback Footage shall
remain unchanged.
2) For all
existing drilling units with a Setback Footage that is 660 feet or greater, the
revised Setback Footage shall be re-established to 660 feet.
d) After the effective date of
this rule, any Existing PRU not subject to a Penalty Allowable may produce at
the PRU Deliverability.
e) After
the effective date of this rule, 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 rule shall be determined as follows:
1) For any Existing PRU where the Setback
Footage is equal to or greater than 660 feet, and where the Setback Footage has
been re-established to 660 feet in accordance with subparagraph c) 2) above,
the previously imposed penalty on the allowable established prior to the
adoption of this rule 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 re-established to a 660 feet in accordance with subparagraph
c) 2) above, the previously imposed penalty on the allowable established prior
to the adoption of this rule shall be re-calculated based on the revised
Setback Footage of 660 feet in order to calculate the Penalty Allowable, except
that any Existing PRU that has a recalculated Penalty Allowable of less than 75
MCFD shall be assigned a Penalty Allowable of 75 MCFD.
3) For any Existing PRU, where the Setback
Footage remains unchanged in accordance with subparagraph c) 1) above, the
Penalty Allowable established prior to the adoption of this rule shall remain
in effect, except that any Existing PRU that has a re-calculated Penalty
Allowable of less than 75 MCFD shall be assigned a Penalty Allowable of 75
MCFD.
4) No New PRU may be located
less than 660 feet FUB where the Setback Footage has been re-established to a
660 feet in accordance with subparagraph c) 2) above, or closer than the
applicable Setback Footage that remained unchanged in accordance with
subparagraph c) 1) above, unless approved in accordance with General Rule B-40,
or an alternative is approved by the Commission after notice and
hearing.
g) In
accordance with subparagraph f) 2) above, the Penalty Allowable shall be
calculated as follows:
1) If the Encroachment
Footage encroaches upon only one boundary of said drilling unit, the Penalty
Allowable shall be the greater of 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 boundaries of said drilling unit, then
the Penalty Allowable shall be the greater of 75 MCFD or the cumulative of the
penalties calculated as follows:
Penalty Allowable = PRU Deliverability x Penalty Factor [(1st
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 rule shall have an annual balancing
date of July 1, where the preceding 12 month (July 1 - June 30) sales must be
reconciled with the preceding 12 month Penalty Allowable to determine if the
PRU had excess sales.
2) 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 is eliminated. 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 30 days after the
July 1, may be subject to a civil penalty not to exceed two thousand five
hundred dollars ($2,500.00) per day for every day the PRU produced beyond the
30 day period, and may be subject to further enforcement actions in accordance
with General Rule A-5, and Ark. Code Ann. §
15-72-401
through
15-72-406.
(Source: new rule August 01, 2014)
GENERAL RULE C - OIL
RULE C-1:
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 Commission, will have the
production of oil controlled or regulated as provided in Act 105, General
Assembly, 1939.
(Source: 1992 rule book)
RULE C-2:
REPORTS BY
PRODUCERS
A. Each
producer of oil in any field, and each producer of hydrocarbons in liquid form
at the well head 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.
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
month, the producer may, in lieu of filing a new certificate, notify the Oil
and Gas Commission at El Dorado, Arkansas, and the transporter then authorized
by certificate on file with the Oil and Gas 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. In no instance shall the temporary transporter move
any greater quantity of oil than the estimated amount shown in said
notice.
The "Producer's Certificate of Compliance and Authorization to
Transport Oil or Gas from Lease," when properly executed and approved by the
Oil and Gas 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:
(1) The
operating ownership of the lease changes, or
(2) The transporter is changed, or
(3) The permit is cancelled by the Oil and
Gas Commission.
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 legal quantity of oil on hand 7 a.m., the first day of
such month; the scheduled allowable to the date disconnected; and the quantity
of oil moved from the particular lease during the current month. In such case
the producer shall furnish to the connecting transporter a certified statement
under oath showing the lease stock on hand 7 a.m., the date of new connection.
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
Oil and Gas Commission or their authorized agent.
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. Each transporter shall maintain necessary records
of lease allowables and quantities of oil removed from the leases to which he
is connected, whereby he can determine the calculated quantity of legal oil on
hand at the close of each calendar month with respect to such leases. 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 Oil and Gas Commission, less the quantity of oil removed from the
respective lease tanks during the current month. If the calculated balance so
determined is less than the actual gauged quantity on hand as reported by the
producer on "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. 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.
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. Where there is more than one transporter moving oil from the same
lease, the producer and transporters are required to furnish to each other
information as the quantity of oil on hand, the quantity transported from lease
tanks and any additional information necessary to establish to the satisfaction
of each person involved the legal status of the oil produced.
B. 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. Such report for
each month shall be prepared and filed according to the instructions on the
form, on or before the 15th of the next succeeding
month.
(Source: 1992 rule book)
RULE C-3:
REPEALED
Rule Repealed Effective October 19, 2018 in accordance with Act
781 of 2017
RULE C-4:
REPEALED
Rule Repealed Effective October 19, 2018 in accordance with Act
781 of 2017
RULE C-5:
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:
A. There
shall be assessed a charge not to exceed fifty (50) mills (
Acts
2001, No. 1188, General
Assembly) on each barrel of crude oil or petroleum marketed or used from a
field or pool each month. 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." Effective on and after January 1, 2002,
the oil conversation assessment shall be 43 mills.
B. The first purchaser, user or holder for a
period of thirty 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 or thirty (30) days from the lease each month, and remit the
amounts.
C. 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 the show the deductions under
this order on the regular payment statements to producers and royalty owners or
parties in interest.
D. 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 rule as 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 in the manner stated.
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
rule are payable to the Commission, shall remit any sum so due to the
Commission in accordance with these rules .
(Source: 1992 rule book; amended Novermber 27, 2001)
RULE C-6:
REPEALED
Rule Repealed Effective July 15, 2017
RULE C-7:
REPEALED
Rule Repealed Effective July 17, 2009
RULE C-8:
REPEALED
Rule Repealed Effective October 19, 2018 in accordance with Act
781 of 2017
RULE C-9:
REPEALED
Rule Repealed Effective October 19, 2018 in accordance with Act
781 of 2017
RULE C-10:
ESTABLISHMENT OF WELL SET-BACK 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 general rule, all oil well set back 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:
1) ten (10) acre drilling units, described as
a quarter (¼) quarter (¼) quarter (¼) of a governmental
section;
2) twenty (20) 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 (¼) quarter (
¼) of a governmental section;
3) forty (40) acre drilling units, described
as a quarter (¼) quarter (¼) of a governmental section;
and
4) eighty (80) 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 (¼) of a
governmental section; are set at two hundred and eighty (280) feet 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 and eighty (280) feet 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 Commission after notice and a
hearing in accordance with General Rules A-2, A-3 and other applicable hearing
procedures.
(Source: new rule February 19, 2009)
GENERAL RULE D - GAS
RULE D-1:
REPEALED
Rule Repealed Effective October 16, 1953.
RULE D-2:
REPEALED
Rule Repealed Effective February 19, 2009
RULE D-3:
REPEALED
Rule Repealed Effective February 19, 2009
RULE D-4:
REPEALED
Rule Repealed Effective February 19, 2009
RULE D-5:
REPEALED
Rule Repealed Effective February 19, 2009
RULE D-6:
REPEALED
Rule Repealed Effective February 19, 2009
RULE D-7:
NATURAL GAS TO BE
METRED
a) Wellhead
Production Meters:
1) For protection of
correlative rights of all parties, the operator of a natural gas well shall
meter or caused 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, is utilized to provide for
proper production allocation back to the individual well from a central point
production meter or central point sales meter, which ever meter occurs
first.
2) All required meters shall
be calibrated at least once per calendar year. 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 Commission. Such records shall be maintained by
the operator for a period of at least five (5) years.
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:
All meters, measuring the volume of gas sold, shall be calibrated
at least once per year. The Director or his 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. The records of such
calibration shall be maintained by the person responsible for the meter and
shall be available for inspection by the commission. Such records shall be
maintained by the person responsible for the meter for a period of 5
years.
(Source: 1992 rule book; amended January 22, 2009)
RULE D-8:
MONTHLY NATURAL GAS PRODUCTION REPORTS
a) 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 Rule F-3, shall be
reported by the operator monthly in a form prescribed by the Director. 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 name and address of the person other
than the operator who has sold gas, the 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 the approximate well ownership percentage of
the person other than the operator who has sold gas. 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 commission.
b) 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. 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. 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 General Rule F-3.
(Source: 1992 rule book; amended November 16, 2008; amended
August 21, 2009)
Rule Repealed Effective July 15, 2017
RULE D-10:
REPEALED
Rule Repealed Effective October 19, 2018 in accordance with Act
781 of 2017
RULE D-11:
REPEALED
Rule Repealed Effective July 15, 2017
RULE D-12:
REPEALED
Rule Repealed Effective October 19, 2018 in accordance with Act
781 of 2017
RULE D-13:
REPEALED
Rule Repealed Effective July 15, 2017
RULE D-14:
GAS
ASSESSMENT
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:
(A) There shall
be assessed against the persons involved, a charge not to exceed ten (10) mills
on each one thousand (1,000) cubic feet of gas produced and saved each month
from a well. 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." Effective on and after January 1, 2002, the gas
conservation assessment shall be 9 mills.
(B) The person selling gas at the first point
of sale, who is hereby defined to be the party initially responsible for
distributing the 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 Commission
at the same time and periods as said purchasers make their regular gas
payments.
(C) 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 parities in
interest.
(D) 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.
(E)
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 these rules 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.
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 rule are payable to the Commission, shall remit any sum so
due to the Commission in accordance with these rules.
(Source: 1992 rule book; amended Novermber 27, 2001; amended
October 24, 2009)
RULE
D-15:
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.
(2) A
manifold having block valves on each end of the meter run, and two bypass
valves with a bleeder between the bypass valves. During normal operations, the
two bypass valves will be closed, with at least one bypass valve sealed, and
the bleeder valve will be open and unplugged.
(b) Whenever the manifold described in
Section (a)(2) is employed, a notation will be made on the orifice meter chart
any time a seal is broken or replaced. This notation will include the seal
number broken, the seal number replaced, the reasons for this action, and
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
Section (a)(2) 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.
(Source: 1992 rule book)
RULE D-16:
BACK PRESSURE
TESTS FOR NATURAL GAS PRODUCTION ALLOWABLE DETERMINATION
a) Applicability
This rule shall only apply to dry natural gas wells for which it
is necessary to determine the PRU Deliverability in accordance with General
Rules A-7, B-43, B-44, D-19, D-21, or the request of the Director, or his
designee, to conduct a back pressure test on a dry natural gas well.
b) Definitions
1) "Existing PRU" shall mean a production
reporting unit, which is either an individual sources of supply or approved
commingled producing zones within a dry natural gas well which was previously
productive prior to the effective date of this rule.
2) "IOPT" shall mean an Initial One-Point
Test performed to determine PRU Deliverability.
3) "New PRU" shall mean 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 rule.
4) "Permit Holder" shall mean the person to
whom the permit is issued and is responsible for all regulatory requirements
relative to the production well.
5)
"Production Test" shall mean any One-Point Test that is performed to determine
PRU Deliverability which occurs after a successful One-Point Test has been
performed.
6) "PRU Deliverability"
shall mean 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) An IOPT shall be conducted for any New PRU
for the purpose of determining the PRU Deliverability. 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 General Rule D-21, determining
marginal well status for severance tax purposes in accordance with General Rule
A-7, an additional completion request in accordance with D-19, or if requested
by the Director or his 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 designee, at least seventy-two (72) hour
notice in advance of an IOPT or a Production Test.
2) When to Conduct Test - The Permit Holder
shall conduct the IOPT within ten (10) calendar days of commencement of
production of a New PRU. The Director, or his designee, shall retain the right
to require a re-test of an Existing or New PRU at any time.
Additionally, the Permit Holder shall have the right to request 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)
AOGC Staff Witness - The IOPT is required to be witnessed by a representative
of the AOGC unless the Permit Holder is notified by the AOGC that the test
shall not be witnessed. Production tests for purposes of establishing marginal
well determination, in accordance with General Rule A-7, are required to be
witnessed by a representative of the AOGC. AOGC staff witness will be subject
to notice by the Permit Holder in accordance with subparagraph (e) (1) above
and subject to availability of an AOGC staff witness. All tests shall be
conducted during normal working hours of the Commission unless otherwise
approved by the Director or his designee.
f) Testing Methodology - An IOPT or
Production Test shall be conducted to determine the PRU Deliverability. All
tests shall be reported on a form prescribed by the Director, or his designee,
and conducted as follows:
1) Before a test is
started, the wellbore should be cleared of any accumulated fluids.
2) The Dry Natural Gas from the Existing or
New PRU shall be flowed through the production facilities into the pipeline for
a minimum of 24 hours. 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 the Director or his designee.
3) 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. The Director, or his designee, may
authorize an alternative method to determine PRU Deliverability.
(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)
RULE D-17:
GENERAL RULE FOR THE REGULATION OF NATURAL GAS
PIPELINES
a) Definitions
1) Jurisdictional Pipeline means any onshore
natural gas pipeline regulated under Federal Regulation 49 CFR Part 192 as
amended, which is within the jurisdiction of the Arkansas Oil and Gas
Commission in accordance with Ark. Code Ann. §
15-71-110
as amended.
2) Non-Jurisdictional
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 CFR Part 192 as amended, which is within the jurisdiction
of the Arkansas Oil and Gas Commission in accordance with Ark. Code Ann. §
15-71-110
as amended.
3) Perennial Stream
means: a stream that has flowing water year-round during a typical year, the
water table is located above the stream bed for most of the year, groundwater
is the primary source of water for stream flow, and runoff from rainfall is a
supplemental source of water for stream flow.
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 Arkansas Oil and Gas Commission in
accordance with Ark Code Ann. §
15-71-110
as amended.
b)
Applicability
1) For purposes of this Rule,
the jurisdiction of the Arkansas Oil and Gas Commission, as specified in Ark
Code Ann. Ann. §
15-71-110
as amended, extends and includes:
A) The
production process or production facility as defined in Ark Code Ann. §
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) Every Pipeline Operator transporting
natural gas by pipeline from the well is subject to the applicable provisions
of this rule. Natural gas pipelines from the well, to a custodial transfer
meter located on the well pad, are exempt from the provisions of this
rule.
c) General
Requirements for all Jurisdictional and Non-Jurisdictional Pipelines:
1) Each Pipeline Operator shall apply, on a
form prescribed by the Director, for an initial statewide permit to construct
and operate a natural gas pipeline system. The initial permit application shall
contain at a minimum the following:
A) Name,
address and contact information for the Pipeline Operator;
B) 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 Arkansas Oil and Gas
Commission, including all public road, railroads and perennial stream
crossings;
C) A determination as to
what pipelines are jurisdictional;
D) Submission of the applicable permit fee as
follows:
(i) no permit fee is required for 1
mile or less, provided the pipeline does not cross a public road, railroad or
perennial stream.
(ii) less than 50
miles of pipeline, including pipelines in (c)(1)(D)(i) above which cross public
roads, railroads or perennial streams - $500.00
(iii) 50 miles to less than 100 miles of
pipeline - $1,500.00
(iv) 100 miles
to less than 250 miles of pipeline -$2,500.00
(v) 250 miles or more of pipelines -
$5,000.00
2)
Each Pipeline Operator shall be required to submit an annual permit renewal by
January 31 of each year.
3) 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
paragraph (c)(1)(D) above. The renewal permit shall also contain the Pipeline
Operator's determination as to which pipelines are jurisdictional.
4) Each Pipeline Operator shall submit a
Notice of Construction or Repair, on a form prescribed by the Director, prior
to commencing construction or within 48 hours after completing repair, for each
segment or project length of pipeline constructed during the year. The Notice
shall indicate the location and extent of the natural gas pipelines to be
constructed or repaired.
5) 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. 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 in-patient hospitalization; or
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
subparagraphs (A) or (B) above.
d) Requirements for all Non-Jurisdictional
Pipelines
1) All pipelines crossing any stream
or stream bed shall comply with applicable state rules and federal regulations.
Additionally, any stream crossing of perennial streams, constructed on or after
December 16, 2007, shall maintain a minimum of fifty (50) feet of undisturbed
stream bank for the protection of the stream. However, the fifty (50) feet 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) Each Pipeline Operator shall place and
maintain appropriate signage at all natural gas pipeline crossings of public
roads and railroads. 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 rule, shall
be buried at least twenty-four (24) inches 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 CFR Part 192 Subpart A thru Subpart 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 CFR
Part 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 CFR Part 191 as amended, which are herein incorporated
by reference, and all such reports shall be submitted to the Arkansas Oil and
Gas Commission.
4) All Pipeline
Operator of Jurisdictional Pipelines shall be subject to the applicable drug
and alcohol testing requirements contained in Federal Regulation 49 CFR Part
199 as amended, which are herein incorporated by reference.
5) All Jurisdictional Pipelines which contain
over 100 PPM hydrogen sulfide shall also be subject to the provisions of
subparagraph (f) below, unless the provisions of subparagraph (f) are less
stringent than any applicable requirement of this subparagraph (e).
f) Additional Requirements for All
Pipelines Containing 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, and
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, and
C) No natural gas pipeline may be operated
after new construction, repair or relocation until it has been successfully
tested for at least one hour with a minimum pressure of 1.25 times the maximum
operating pressure to substantiate the maximum operating pressure with all
leaks located and eliminated, and
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
31st 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) 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. This plan must be reviewed and updated as
often as necessary. A review must be conducted annually but not to exceed 15
months between reviews.
3) Each
Pipeline Operator shall have a procedure for continuing surveillance of its
facilities and take appropriate action regarding, failures, corrosion and
operating conditions.
4) Each
Pipeline Operator must develop and carry out a damage prevention program to
prevent damage to its natural gas pipelines from excavation activities. Each
Pipeline Operator shall be a member of the state wide "one-call" system. 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) Each Pipeline Operator shall establish
written procedures to minimize the hazards resulting from a natural gas
pipeline emergency event. Each plan must include at a minimum:
A) Methods of receiving and identifying an
event which requires immediate response; and
B) Methods for establishing and maintaining
adequate communication with appropriate emergency response and public
officials; and
C) Methods for
determining safe areas related to evacuation and security during an event;
and
D) Methods for training
employees of their duties and responsibilities during an event.
6) Each Pipeline Operator shall
develop and implement a written continuing public awareness plan which includes
provisions for educating the public, appropriate governmental organizations and
persons engaged in excavation activities. 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. The program must include activities to
advise affected municipalities, schools, businesses and residents along the
pipeline right of way. 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) 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. Patrols shall
be conducted and documented at least twice each calendar year, not to exceed 7
½ months between patrols.
10) 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. 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 pipelines
maximum operating pressure, once each calendar year and not to exceed 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 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 15 months.
14) Each Pipeline
Operator shall maintain records associated with operation and maintenance of
the pipeline required in this section.
15) 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. 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 non-essential persons from the area and (iv) ensure
the public is adequately protected.
(Source: (Order No. 90-97) October 28, 1997; amended December 16,
2007; amended September 14, 2008; amended October 24, 2009; amended January 20,
2014)
RULE
D-18:
AUTHORITY TO COMMINGLE
a) This rule authorizes the Director of
Production and Conservation, or his designee, to approve certain commingle
requests as detailed in this rule. This rule is applicable for administrative
approval of commingling of multiple common sources of supply on an individual
well basis only, and includes previously completed and/or uncompleted sources
of supply in a well, with no restriction on rate of production. The rule is not
applicable on a field-wide basis.
b) All common sources of supply classified by
the Commission as uncontrolled, are exempt from the provisions of this rule and
are permitted to be commingled without application, only when commingled with
other uncontrolled sources of supply. Upon completion of the commingling
activities, reporting in accordance with Rule B-5 is required.
c) All common sources of supply previously
approved and commingled in wells before the effective date of this rule are
allowed to continue in effect for the life of the well.
d) Commingling is permitted without
application for the Middle Atoka, as defined by General Rule B-44 (a) (4). Upon
completion of commingling activities, reporting in accordance with Rule B-5 is
required.
e) Requests for the
commingle 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 rule, and must be brought before the
Commission for approval following proper notice and hearing:
1) A wildcat well; or
2) A well located within an exploratory unit
established by Commission Order; or
3) A well in which the commingling of
multiple common sources of supply will result in an unapproved additional
completion within the drilling unit; or
4) A well in which the primary reservoir
drive mechanism for a requested zone to be commingled is a water drive;
or
5) A well in which the ownership
between the commingled zones is not common, unless all owners, as defined in
Ark. Code. Ann. (1987) §
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 rule shall be
submitted on a form prescribed by the Director of Production and Conservation
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;
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) Upon review and approval of the
application and if no objections are received by the Director of Production and
Conservation within 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. Approved applications are only valid for one 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 of Production
and Conservation, 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
of Production and Conservation receives an objection to a commingle application
during the notice period specified in (f) above, or if the application does not
satisfy the requirements of this Rule and is denied by the Director, the
applicant may request to have the matter placed, in accordance with General
Rules A-2, A-3, and other established procedures, on the docket of a regularly
scheduled Commission hearing.
(Source: new rule February 2, 2006; amended January 22, 2009;
amended June 5, 2009)
RULE
D-19:
ADDITIONAL COMPLETIONS WITHIN COMMON
SOURCESOF SUPPLY WITHIN A DRILLING UNIT
a) This rule 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 rule is not applicable on a
field-wide basis, or within Exploratory Units.
c) Application for additional completions
shall be submitted to the Director of Production and Conservation on a form
prescribed by the Director, and contain the following information:
1) The location of the unit;
2) The location of all well(s) showing the
productive zones in each well within the unit for which the additional
completions are requested;
3)
Initial and current pressure(s) 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 Ark. Code
Ann. §
15-72-102(9),
in the subject unit and all offset operators in all adjacent established units
including all owners, as defined by Ark. Code Ann. §
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 of Production and Conservation written objections within fifteen (15)
days after receipt of the application by the Director of Production and
Conservation f) Any offset operator or owner noticed in accordance with
paragraph e) 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 of Production and Conservation.
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 20% reduction in the original
pressure 5 years after the first completion in that same source of supply;
or
5) The other unit completion(s)
in the common source of supply have each produced less than 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 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 15 days after the receipt of the
application, the Director of Production and Conservation shall approve the
application.
h) If an
objection is received or if the application does not satisfy the requirements
of this Rule, the application shall be denied. If an application is denied, or
if the reason for an additional completion request is not addressed by this
rule, the Applicant may request to have the matter placed, in accordance with
established procedures, on the docket of a regularly scheduled Commission
hearing.
(Source: new rule February 2, 2006; amended April 13,
2008)
RULE D-20:
NOISE LEVEL REQUIREMENTS FOR NON-WELLHEAD COMPRESSOR
FACILITIES
a)
Applicability:
1) The provisions of this rule
apply to all non-wellhead compressor facilities or stations used in the
production process, as defined in Ark Code Ann. §
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 non-wellhead compressor facilities in
operation as of the initial effective date of this rule shall be in compliance
with the provisions of this rule by July 1, 2012.
3) All non-wellhead compressor facilities
that become operational after the initial effective date of this rule shall be
in compliance with the provisions of the rule within one year of commencing
compressing operations.
b) Definitions:
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 private
residence, school, hospital, church, nursing home, or other building of a type
that is regularly used for overnight accommodation.
4) "Non-well head compressor facility or
station" means any compressor facility or station used for the purpose of
compressing natural gas for pipeline transportation. 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.
5) "Normal full-load operating
conditions" means the normal operating condition of the non-wellhead 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 non-wellhead
compressor facility or station during normal full-load operating conditions
shall not exceed 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 non-wellhead 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.
3) The Leq contribution due to a non-wellhead
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 non-wellhead compressor facility or station under test.
The following extraneous noise shall be excluded from the measurements to the
fullest extent possible:
a) Wind;
b) Vehicular Traffic;
c) Residential heating, ventilating, and air
conditioning;
d) Aircraft
over-flights;
e) Bird
sounds;
f) Insect sounds; and g)
Other noise generating equipment unrelated to the non-wellhead compressor
facility or station.
e) Any owner or operator of a non-well head
compressor facility or station found to be in violation of the provisions of
this rule shall pursue with reasonable diligence a remedy to correct the
violation. Any violation shall be considered an "operational" violation in
accordance with General Rule A-5.
(Source: new rule November 1, 2011)
RULE D-21:
PROCEDURES FOR
DETERMINING THE PRODUCTION ALLOWABLE FOR DRY NATURAL GAS PRODUCTION
WELLS
a) Applicability
This rule shall only apply to dry natural gas wells for which it
is necessary to determine the PRU Deliverability in accordance with General
Rules B-43, B-44 and other applicable General Rules, Field Rules or Commission
Orders. This rule shall not apply to any PRU subject to provisions of General
Rule B-45.
b) Definitions
1) "Allowable" shall mean the PRU
Deliverability for a New or Existing PRU is allowed to produce and sell on a
per day basis.
2) "Encroachment
Footage" shall mean 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" shall mean 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
rule.
4) "New PRU" shall mean 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 rule.
5) "Penalty Allowable" shall mean 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" shall mean the factor
which is multiplied by the New or Existing PRU to impose a penalty (or
reduction) upon the PRU Deliverability.
7) "PRU Deliverability" shall mean 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 General Rule D-16.
8) "Setback Footage" shall mean the required
minimum distance a New or Existing PRU must be from the drilling unit
boundary.
9) "FUB" shall mean
distance from a drilling unit boundary line.
c) Any New or Existing PRU, not subject to a
Penalty Factor in accordance with subparagraph f) 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)
2) A New or
Existing PRU with a PRU Deliverability of less than 75 MCFD shall have an
allowable determined as follows: Allowable = 75 MCFD. PRU Deliverability of
less than 75 MCFD shall be demonstrated by either:
A) Conducting a test utilizing the
methodology specified in General Rule D-16; or
B) 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 boundary of said drilling unit, the Penalty Allowable
shall be the greater of 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 boundaries of said drilling unit, then
the Penalty Allowable shall be the greater of 75 MCFD or the cumulative of the
penalties calculated as follows:
Penalty Allowable = PRU Deliverability x Penalty Factor [(1st
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
1) An Existing or New PRU subject to a
Penalty Allowable in accordance with this rule shall have an annual balancing
date of July 1, where the preceding 12 month (July 1 - June 30) sales must be
reconciled with the preceding 12 month Penalty Allowable to determine if the
PRU had excess sales.
2) 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 is eliminated. 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 30 days after the
July 1, may be subject to a civil penalty not to exceed two thousand five
hundred dollars ($2,500.00) per day for every day the PRU produced beyond the
30 day period, and may be subject to further enforcement actions in accordance
with General Rule A-5, and Ark. Code Ann. §
15-72-401
through
15-72-406.
(Source: new rule August 01, 2014)
RULE D-22
REQUIREMENTS FOR LEASE RIGHTS GAS SUPPLY
LINES
a) Definitions
1) "Director" shall mean the Director of the
Oil and Gas Commission.
2)
"Existing Lease Rights Gas Supply Line" shall mean a pipeline, under
jurisdiction of the Arkansas Oil and Gas Commission ("AOGC") as defined in Ark.
Code Ann. §
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(s), and was
constructed before the initial effective date of this rule (January 15,
2015).
3) "New Lease Rights Gas
Supply Line" shall mean a pipeline, under jurisdiction of the Arkansas Oil and
Gas Commission ("AOGC") as defined in Ark. Code Ann. §
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(s), and was
constructed after the effective date of this rule (January 15, 2015).
4) "Lease Rights Gas Supply Line Operator"
shall mean a Lease Rights Gas Supply Line owner who has an agreement
authorizing natural gas supply, who accesses directly from the Well Operator
Connection, and who owns or operates and is responsible for the construction,
operation and maintenance of a Lease Rights Gas Supply Line.
5) "Lease Rights Gas" shall mean the gas
owned and controlled by the Lease Rights Gas Supply Line Operator once it
passes the Well Operator Connection.
6) "Well Operator Connection" shall mean 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
AOGC as defined in Ark. Code Ann. §
15-71-110,
are not subject to the provisions of this rule, 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) Utilizing the
services of a plumber licensed by the State of Arkansas, the New Lease Rights
Gas Supply Line Operator shall properly install one or more properly-sized
regulator(s) 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. 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) Utilizing the services of a plumber
licensed by the State of Arkansas, New Lease Rights Gas Supply Lines shall be:
A) Constructed of steel or plastic which is
designed, manufactured and intended for natural gas service in accordance with
industry standards and be tested and free of leaks prior to placing into
service. Each test shall be at a pressure of fifty (50) psig for a period of
thirty (30) minutes. All piping shall be installed in a manner which will
minimize strain or external loading. 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. Tracer wire may not be wrapped
around the plastic pipe and contact with the pipe should be avoided with at
least two (2) inches 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 (18) inches 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 1" in height and ¼" in stroke "WARNING - DANGER -
NATURAL GAS PIPELINE", and including the name, address and 24hour contact
information of the New Lease Rights Gas Supply Line Operator; and
6) 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. 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) 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. The Director shall send a letter to each Existing Lease Rights Gas
Supply Line Operator notifying them of the requirements of this Rule. Within
six (6) months from the date the notification letter was sent, all Existing
Lease Rights Gas Supply Line Operators shall document compliance with items 1
through 6 below, by the submission of documentation to the Director, or his or
her designee. If the Existing Lease Rights Gas Supply Line Operator fails to
demonstrate compliance with items 1 through 6 below, or if the Existing Lease
Rights Gas Supply Line Operator fails to comply with items 1 through 6 below,
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:
1) The Lease Rights Gas Supply Line Operator
shall affirm that the Existing Lease Rights Gas Supply Line is:
A) Constructed of steel or plastic which 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
B) Buried and have at least a minimum of
eighteen (18) inches 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; and
2) The Lease Rights Gas Supply Line Operator
shall also affirm that all plastic pipping has a tracer wire installed with the
piping, or other means of locating the pipe underground. Tracer wire may not be
wrapped around the plastic pipe and contact with the pipe should be avoided
with at least two (2) inches between the wire and the Lease Rights Gas Supply
Line. Trace 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; or
B) Crosses any property
not owned by the Lease Rights Gas Supply Line Operator; or
C) Is within twenty-five (25) feet of the
Lease Rights Gas Supply Line Operator's property line(s).
3) Existing Lease Rights Gas Supply Line
Operators shall properly install, or maintain, one or more properly sized
regulators on the Lease Rights Gas Supply Line at the Well Operator Connection,
and properly install, or maintain, an excess flow valve as close to the Well
Operator Connection as reasonably possible.
4) All repairs or relocation of an Existing
Lease Rights Gas Supply Lines must be performed by a plumber licensed by the
State of Arkansas and be in accordance with all applicable above
provisions.
5) 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 1" in height and ¼" in stroke "WARNING - DANGER -
NATURAL GAS PIPELINE", and including the name, address and 24-hour contact
information of the Lease Rights Gas Supply Line Operator; and
6) Existing Lease Rights Gas Supply Line
Operator 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. 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.
7) The Well Operator
shall properly install and maintain odorization facilities upstream of the
Lease Rights Gas Supply Line.
e) 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 Arkansas Oil and Gas Commission and
Arkansas Department of Environmental Quality rules . Produced fluids shall not
be discharged onto the ground surface or into waters of the state. Any spill of
produced fluids shall be remediated in accordance with applicable Arkansas Oil
and Gas Commission and Arkansas Department of Environmental Quality rules
.
f) 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 sent in accordance
with subparagraph (d) 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. 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)
All Lease Rights Gas Supply Lines Operators shall maintain compliance with the
provisions of this Rule. If a Lease Rights Gas Supply Line Operator fails to
comply with the provisions of this Rule, the Director or his or her designee
shall give Notice of the Violation, in accordance with General Rule A-5, to the
Lease Rights Gas Supply Line Operator. The Lease Rights Gas Supply Line
Operator shall have thirty (30) days to comply with the Notice of Violation. If
the Lease Rights Gas Supply Line Operator fails to comply or properly request a
review or appeal in accordance with General Rule A-5, 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 Rule. Any appeal of a Director's
Decision for a Notice of Violation issued in accordance with this subparagraph
shall not be subject to the filing fee required in accordance with General Rule
A-2 or A-3.
h) Lease Rights Gas
Supply Line Operators are no longer subject to the provisions of this rule if
the well, where the Well Operator Connection is located, is transferred to the
Lease Rights Gas Supply Line Operator in accordance with General Rule B-11.
(Source: new rule January 15, 2015; amended March 1, 2016)
GENERAL RULE E -
TRANSPORTATION
RULE
E-1:
PIPE LINES, PURCHASERS AND
TRANSPORTERS
(A) No
carrier by pipe line and no gathering system shall transport oil from any lease
or wells if the said pipe line 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 Commission or any conservation laws of the State with
reference to oil and gas.
(B) No
pipe line company shall transport oil from any gathering system which the said
pipe line 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.
It shall be the duty of the pipe line company to suspend
transportation of any oil from said gathering system until such time as such
pipe line 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) 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 pipe line 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. Connections shall be accepted and taken by the pipe
line which by geographical location and least expense is the logical connection
unless some other line is willing to accept the same. 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 pipe lines make
connections to their own wells or wells of affiliated companies.
(Source: 1992 rule book)
RULE E-2:
REPORTS FROM OIL
PIPE LINES, TRANSPORTERS AND STORERS
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 pipe line within the State of
Arkansas and all movements of oil by watercraft, or by trucks or other
conveyances except railroads, from leases to storers or refiners; between
transporters within the State; between storers within the State; between
refiners within the State; and between storers and refiners within the
State.
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.
The transporters and storers reports for each month shall be
prepared and filed according to instructions on the form, on or before the
15th day of the next succeeding month.
(Source: 1992 rule book)
RULE
E-3:
EXPLORATION AND PRODUCTION FLUID GATHERING,
HANDLING AND TRANSPORTATION
a) Definitions
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 Commission;
enhanced recovery operations; or natural gas storage operations, or
B) Produced water and/or other fluids from A)
above, which prior to re-injection 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 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 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.
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.
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 storage facility, surface disposal facility or an injection
well disposal facility.
4)
"Exploration and Production Fluid Transporter" means an operator of an
Exploration and Production Fluid Transportation System.
5) "Transportation Tank" means an assembly,
compartment, tank or other container that is used for transporting or
delivering Exploration and Production Fluid.
b) No person shall operate an Exploration and
Production Fluid Transportation System without an Exploration and Production
Fluid Transportation System permit. Application for which shall be made on
forms prescribed by the Director. 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) 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. 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 30 days following
the date of notification.
d) The
application shall, at a minimum, include:
1) A
permit fee of $100.00 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 manufacturers serial number or other identifying
number for Transportation Tank.
4)
An Entity Organizational Report on a form prescribed by the Director.
e) If the applicant satisfies all
requirements of this rule, the Director shall issue an Exploration and
Production Fluid Transportation System permit and permit sticker for each
Transportation Tank. 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. 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) Exploration and Production Fluid
Transportation System permits shall be renewed annually on July 1 of each year,
commencing on July 1, 2010; and 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 well lease or unit name, well or facility
operator (fluid generator), the date received, the amount per pick up, type of
fluid, and the name and location of the permitted off-site temporary storage
facility, permitted surface disposal facility or permitted injection well
disposal facility.
2) Records shall
be maintained a minimum of three (3) years at the Arkansas office of the
Exploration and Production Fluid Transportation System permit holder, and shall
be made available to 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) Exploration and Production Fluid
Transporters shall only transport Exploration and Production Fluid to a
permitted well for re-use in the well drilling or well completion process, a
permitted off-site temporary storage facility, a permitted surface disposal
facility or a permitted injection well disposal facility. 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 Arkansas
Department 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 non-exempt waste (such as used motor or
compressor oil) under Subtitle C of the Federal Resource Conservation and
Recovery Act of 1976.
5) All
Transportation Tanks shall contain the name and phone number of the Exploration
and Production Fluid Transporter 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
rule may result in revocation of the Exploration and
Production Fluid Transportation System permit, and/or the
assessment of civil penalties in accordance with General Rule A-5.
(Source: new rule January 22, 2009; amended October 24,
2009)
GENERAL RULE F -
PROCESSING
RULE
F-1:
REPEALED
Rule Repealed Effective October 19, 2018 in accordance with Act
781 of 2017
RULE F-2:
REFINERY REPORTS
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. Such report for each
month shall be prepared and filed according to instructions on the form, on or
before the 15th day of the next succeeding
month.
(Source: 1992 rule book)
RULE F-3:
GASOLINE PLANT
REPORTS
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.
Such reports for each month shall be prepared and filed according
to instructions on the form on or before the 15th
day of the next succeeding month.
(Source: 1992 rule book)
GENERAL RULE G - ABANDONED AND ORPHAN WELL
RULE G-1:
ABANDONED OR LEAKING WELL AND WELL SITE
REMEDIATION
a) This rule
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 2 years; or
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 and agreement to continue use
of the well has not been granted by the lease holder, or
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; or
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 Ark Code Ann. §
15-71-116;
or
E) a well that has been ordered
to be plugged by the Commission and the Permit Holder has failed to do so
within the time frame specified in the Commission Order; or
F) a well site which has not been properly
restored following the completion of well plugging activities.
2) "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.
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.
4) "Director" means the Oil and Gas
Commission Director of Production and Conservation.
5) "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 salt water, oil, gas, or other deleterious
substance into any fresh water formation or onto the surface of the land in the
vicinity of the well.
6) "Well Site
Restoration" means remediation of a well site, including but not limited to the
following activities: an emergency clean-up of spilled crude oil or saltwater;
remediation of conditions endangering the public health or safety, or
contaminating or potentially contaminating surface waters, groundwater, or the
surface of the land; 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 surface waters,
groundwaters or the surface of the land; or a repairing a well leaking natural
gas or hydrogen sulfide gas endangering or potentially endangering public
safety or creating a potential a fire hazard.
c) If the Director finds, upon inspection
and/or review of 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, re-plug, repair, or restore so as to remedy the
situation.
e) If the Permit Holder
fails to properly plug, re-plug, repair, or restore so as to remedy the
situation within 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 Rule.
f)
The Director may then authorize any person to enter upon the land and properly
plug, re-plug, repair, or restore so as to remedy the situation. The Director
may dispose of all well site equipment and hydrocarbons, to offset the costs of
properly plugging, re-plugging, repairing, or restoring so as to remedy the
situation. Proceeds from any public sale, auction or private sale of all well
site equipment or hydrocarbons shall be deposited into the Plugging Fund or
used to offset plugging costs. All work completed under this rule shall be paid
with funds from the Abandoned and Orphan Well Plugging Fund.
g) The Permit Holder shall reimburse the
Commission for all costs expended to remedy the situation. All payments shall
be by cashier's checks or money order, and shall be deposited in the Abandoned
and Orphaned Well Plugging Fund. Failure to reimburse the Commission will
result in the initiation of Commission enforcement action to recover the
expended funds. 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. 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 General Rule B-2, to insure against the
plugging of future abandoned wells not plugged by the Permit Holder.
(Source: new rule April 13, 2008; amended November 26,
2009)
RULE G-2:
PLUGGING OF ORPHAN WELLS
a) Definitions:
1) "Orphan Well" means a well for which a
Permit Holder can not be located, there is no record the well is covered by a
Commission required bond by the last known permit holder of record, and no fees
have ever been paid on the well in accordance with Ark. Code Ann. §
15-71-110.
2) "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
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.
4) "Director" means the Oil and Gas
Commission Director of Production and Conservation.
b) If after review of the Commission records,
the Director 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. Following designation as an orphaned well or well site,
the Director may elect to properly plug, re-plug, or restore so as to remedy
the situation, and authorize any person to enter upon the land properly plug,
re-plug, or restore so as to remedy the situation.
c) All work completed under this rule shall
be paid with funds from the Abandoned and Orphan Well Plugging Fund.
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. Proceeds from any public sale, auction or private sale of all well
site equipment or hydrocarbons shall be deposited into the Plugging Fund or
used to offset plugging costs.
(Source: new rule April 13, 2008)
RULE G-3:
TRANSFER OF WELLS
IN THE ABANDONED AND ORPHANED WELL PLUGGING PROGRAM
a) Definitions
1) "Well" as used in this Rule (G-3) shall
only mean wells that are abandoned as defined in General Rule G-1 (a) (1), or
orphaned as defined in General Rule G-2 (a) (1).
2) "Commission" means the Arkansas Oil and
Gas Commission.
3) "Director" means
the Director of Production and Conservation.
b) When a transfer request is received, on a
form prescribed by the Director, 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) $500 per well for
wells less than 3000 feet in depth; and
B) $1000 per well for wells equal to or
greater than 3000 feet in depth; and
2) pay a salvage value for the tanks, pumping
units, and other related equipment, as determined by submission of 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 General Rule B-2 and file all other required organizational
and registration forms.
d) All payments shall be by cashier's checks
or money order, payable to the Commission, and shall be deposited in the
Abandoned and Orphaned Well Plugging Fund.
e) The Director has sole discretion to
approve or deny requests for transfer of the well. 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.
(Source: new rule April 13, 2008)
GENERAL RULE H - CLASS II UIC WELLS
RULE H-1:
CLASS II DISPOSAL
AND CLASS II COMMERCIAL DISPOSAL WELL PERMIT APPLICATION
PROCEDURES
a) Definitions:
1) "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
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."
2) "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.
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 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 Commission;
iii) enhanced recovery operations;
or
iv) natural gas storage
operations; or
B)
Produced water and/or other fluids from (A) above, which prior to re-injection
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 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, provided the commingled fluid wastes do not constitute a
hazardous waste under the Resource Conservation and Recovery Act; 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.
5) "Class V Brine Disposal Well" means a
permitted Class V well, located within an established unit (voluntary or
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 for the purpose of disposal.
6) "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. It is composed of rock layers
that are impermeable or distinctly less permeable than the injection zone
beneath it. There may be multiple confining layers above an injection
zone.
7) "Disposal system" means a
system for disposing of Class II Fluids.
8) "High volume disposal system" means a
disposal system with an on-site storage capacity of greater than 1000 barrels
of Class II Fluids.
9) "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 Disposal Wells.
10) "Spent Brine Fluid" means
brine fluid, which prior to re-injection, was produced for the purpose of
processing the brine fluid to remove bromine and other chemical and mineral
constituents of economic value from the brine fluid.
11) "UIC Well" means any of the Class II
Disposal, Class II Commercial Disposal, Class II EOR, or Class V Brine Disposal
Well types.
12) "USDW" means
Underground Source of Drinking Water which is defined in Title 40, Code of
Federal Regulations (40 CFR) Section 144.3, as an aquifer or its portion which:
A) Supplies any public water system (see 40
CFR); or
B) Contains a sufficient
quantity of groundwater to supply a public water system (see 40 CFR) and
currently supplies drinking water for human consumption; or
C) Contains fewer than 10,000 mg/l total
dissolved solids (see 40 CFR); and
D) Which is not an exempted aquifer (see 40
CFR).
b) No
person shall drill, deepen, re-enter, recomplete or operate any UIC Well or
inject into any UIC
Well, without the applicable permits, except as specified in
subparagraph b) 1) below, from the Commission, application for which shall be
made on forms prescribed by the Director. 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 General Rule
H-2 or H-3, except that permits to drill, deepen, or re-enter shall
automatically expire six (6) months from the date of issuance, unless
commencement of the drilling, deepening or re-entry 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.
1) 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) An
injectivity test, step rate test or trial injection test of less than twelve
(12) hours duration may be approved by the Director upon review of the well
construction to determine well mechanical integrity for the protection of the
USDW's and oil and gas resources during the test. The Director 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 Commission
staff of the test.
B) An Applicant
may request approval from the Commission, by filing an application in
accordance with General A-2 and A-3 and other applicable hearing procedures, of
an injectivity test, step rate test or trial injection test of twelve (12)
hours or more in duration.
2) 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. 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.
Drilling may not commence prior to the issuance of a new permit.
3) Permits to recomplete or operate shall
automatically expire one 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.
4) 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 Commission staff.
5)
Permits to drill, deepen, or re-enter a UIC Well may only be issued if the
location complies with General Rule B-3.
c) Failure to comply with the operating
requirements in General Rule H-2 or H-3 may result in revocation of the UIC
Well permit in accordance with subparagraph s) 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 which is not associated with
a High Volume Disposal System shall be maintained and operated in accordance
with AOGC General Rule B-26.
2) Any
surface facility associated with a Class II Commercial Disposal Well or a Class
II Disposal Well that is associated with a High Volume Disposal System shall be
permitted and operated in accordance with Arkansas Department of Environmental
Quality requirements specified in PC&E Rule 1.
3) Any surface facility associated with a
Class II EOR and Class V Brine Disposal Well shall be maintained and operated
in accordance with AOGC General Rule B-26.
e) The application to drill, deepen,
re-enter, recomplete or operate a UIC Well shall include at a minimum:
1) The information required by subparagraph
(h) below, for the existing or proposed UIC Well and any additional information
deemed necessary by the Director for the protection of USDWs; and
2) Accompanied by a drilling permit fee in
the amount of $300.00 if the UIC Well is drilled, deepened, or re-entered;
and
3) Accompanied by a
non-refundable application fee of $100.00 for a Class II Disposal, Class II
EOR, or Class V Brine Disposal Well or $500.00 for a Class II Commercial
Disposal Well to recomplete or operate the UIC Well; and
4) Accompanied by the required financial
assurance in accordance with General Rule B-2; and
5) Accompanied by a Form 1 Organizational
Report in accordance with General Rule B-13; and
6) Be executed under penalties of perjury;
and
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 Commission or in a court of competent jurisdiction in
Arkansas; and
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 Commission or in a
court of competent jurisdiction in Arkansas; and
9) Proof that the UIC Well location complies
with General Rule B-3; and
10) If
the application is for a Class II Disposal Well associated with a Disposal
System that is not a High Volume Disposal System, (i) a plat showing the
location and proposed or existing configuration of the storage tank disposal
facility, (ii) the total disposal storage capacity of Class II Fluids at the
facility, and (iii) a list of the production wells utilizing the Class II
Disposal Well.
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 US
Environmental Protection Agency procedures.
g) Unless otherwise approved by the
Commission, no person shall inject into a UIC well which does not have at a
minimum, five hundred (500) feet for a Class II Disposal Well or seven
hundred-fifty (750) feet for a Class II Commercial Disposal or Class V Brine
Disposal 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 50 feet in thickness. A lesser amount of confining layer(s) 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) If the application
does not contain all of the required information or documents, the Director
shall notify the Applicant in writing. The notification shall specify the
additional information or documents necessary for an evaluation of the
application and shall 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) If the application is for a Class II
Disposal or Class II Commercial Disposal Well, the Applicant shall provide the
name, address, phone, fax and e-mail (if available) of the local or on-site
supervisory or field personnel responsible for the disposal well.
3) 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.
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. 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 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. A new survey is not required for a well to be
converted or deepened well or a plugged well to be re-entered, if the original
well location was surveyed, a copy of which shall be submitted with the
application.
5) The name, geologic
description and the approximate top and bottom elevation, from sub-sea, 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 sub-sea, of the above confining layers, in the proposed or previously
permitted UIC Well. If a previously permitted well is to be converted, a
geophysical log of the previously permitted well shall be submitted showing the
above information. For a proposed well, an induction log from a well in the
immediate vicinity of the proposed UIC Well shall be submitted. 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 well bore diagram of the proposed or
previously permitted well showing from the well head to total depth of the
well, all casings and cementing of casings, any obstructions within well, all
plugs set, tubing and packer setting depth, and all perforations and or open
hole intervals. 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) 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: chloride, pH, specific gravity, total dissolved solids (TDS) and
total percent hydrocarbon (TPH). 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 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; or
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 General Rule B-43 (c)
and (d), General Rule B-44, and the portions of Franklin, Logan, Scott,
Sebastian, and Yell Counties not covered by General Rule B-44; 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 2,500 feet, the specific gravity is 1.085, and the injection
tubing friction loss is 250 psi. Using the formula provided above, the maximum
permitted injection pressure for the well would be 1,642 psig, calculated as
follows:
Step 1: 0.9 x [(1.1 psi/ft x 2500 ft) - [0.433psi/ft x 2500 ft) x
1.085 (specific gravity)] + 250 tubing friction loss]
Step 2: 0.9 x [2750 psi - 1175 + 250 tubing friction loss]
Step 3: 0.9 x [1825]
Step 4: Result = 1642 psig
B) An Applicant may request an increase in
the maximum injection pressure specified in subparagraph j) 8) A) above, or
appeal a Director's decision to issue a permit utilizing a fracture gradient
less than the maximum fracture gradient specified in subparagraph j) 8) A)
above, by filing an application in accordance with General A-2, A-3 and other
applicable hearing procedures. 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(s) 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 1/2 mile radius from the proposed disposal well,
and showing the status of each well as producing, shut-in, disposal, enhanced
recovery, plugged and abandoned, or other status.
10) The Applicant shall submit evidence,
where available, that all plugged and unplugged wells which penetrate the
injection formation, within the ½ mile radius shown on the above plat in
subparagraph j) 9) B), 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. The types of evidence that will be
considered acceptable include, but are not limited to: well completion reports,
cementing records, well construction records, cement bond logs, tracer surveys,
oxygen activation logs, and 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 fresh water 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
Commission, the Arkansas Department 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) Notice of the application shall be given
by the Applicant by 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,
in which the one-half mile radius from the proposed disposal well is situated,
and by 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 mile radius of
the proposed disposal well. 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 Commission. The cost of such notice and mailing of the application shall be
paid for by the Applicant. 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) If notice is for a Class II Commercial
Disposal Well, in addition to compliance with subparagraph i) 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. 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, must be received by the Director within
fifteen (15) days after the publication date of the notice and the date of
mailing or sending to all parties specified in subparagraphs k) and l)
above.
n) If an objection is
received the application shall be deemed denied. 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 General Rules A-2 and
A-3, and other applicable hearing procedures, except that no additional filing
fee is required.
o) If an objection
is not received by the Director and the application is deemed complete, the
permit shall be issued following the required notice period specified in
subparagraph k) above, unless the Director deems it necessary, for the purpose
of protecting USDWs or oil and gas resources, that the application may be
referred to the Commission for determination, and no additional filing fee is
required from the applicant.
p) If
the application does not satisfy the requirements of this Rule, the application
shall be denied. 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 General Rules A-2 and A-3, and other
applicable hearing procedures.
q)
If the Applicant satisfies the requirements of all applicable statutes and this
Rule, 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 5%;
i) That has failed to abate an outstanding
violation of the oil and gas statutes or rules, or comply with an orders of the
Commission as specified in a final administrative decision of the Commission;
or
ii) For which funds have been
obligated and remain outstanding from the Plugging and Restoration Fund to plug
wells, under General Rule G-1 or G-2; or
iii) Who is delinquent in payment of any
annual well fees under General Rule B-2.
B) Was an owner, officer, director, partner,
or member or manager of a limited liability company, or other person with an
interest exceeding 5%;
i) That has failed to
abate an outstanding violation of the oil and gas statutes or rules, or comply
with an orders of the Commission as specified in a final administrative
decision of the Commission; or
ii)
For which funds have been obligated and remain outstanding from the Plugging
and Restoration Fund to plug wells, under General Rule G-1 or G-2; or
iii) Who is delinquent in payment of any
annual well fees under General Rule B-2.
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 5%;
i)
That has failed to abate an outstanding violation of the oil and gas statutes
or rules, or comply with an orders of the Commission as specified in a final
administrative decision of the Commission; or
ii) For which funds have been obligated and
remain outstanding from the Plugging and Restoration Fund to plug wells, under
General Rule G-1 or G-2; or
iii)
Who is delinquent in payment of any annual well fees under General Rule
B-2.
D) If the Director
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 5% in the applicant, has a history of violating an oil and
gas statute, rule, permit condition or order of the Commission, the Arkansas
Department of Environmental Quality, the Arkansas Pollution 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. In
making the determination, the Director may consider:
i) 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
ii) The degree to which past and present oil
and gas related activities directly bear upon the reliability, competence, and
responsibility of the applicant.
E) If a permit is not issued in accordance
with subparagraph o) 2) above, the Applicant may request to have the permit
application referred to the Commission for determination, in accordance with
General Rules A-2 and A-3, and other applicable hearing procedures, except that
no additional filing fee is required.
r) The 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 may
revoke a UIC Well permit or transfer approval if the Permit Holder fails to
meet permit conditions as specified in the UIC Well permit or transfer
approval, the UIC Well permit or transfer approval was issued in error, or the
Permit Holder falsified or otherwise misstated any material information in the
application form.
2) The Director
shall notify the Permit Holder of the UIC Well permit or transfer revocation in
writing. Following the revocation notice the Permit Holder is required to plug
the UIC Well. The Permit holder shall have thirty (30) days from the date of
the UIC Well permit or transfer revocation to appeal the Director's Decision to
revoke the UIC Well permit or transfer approval in accordance with General Rule
A-2, A-3 and other applicable hearing procedures. Operations may not commence
or continue during the appeal process. 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 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 is the owner of the right to operate said UIC Well(s), possesses
the full rights and responsibilities for operating the UIC Well(s) in
accordance with applicable Arkansas law and has the current obligation to plug
said UIC Well(s), who is the assignor, transferor or seller (whether voluntary
or involuntary) of the UIC Well(s).
B) "New Permit Holder" means the individual
or entity acquiring the UIC Well(s) and the right to operate said UIC Well(s),
who obtains the full rights and responsibilities for operating the UIC Well(s)
in accordance with applicable Arkansas law and/or rule or order of the
Commission, who will obtain the obligation to plug said UIC Well(s), and who as
owner or operator in accordance with applicable Arkansas law and/or rule or
order of the Commission is required to hold the permit.
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
subparagraph 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) a
change of ownership of the right to drill and/or operate said UIC Well(s),
along with the full rights and responsibilities for operating the UIC Well(s)
and the obligation to ultimately plug said UIC Well(s); or
B) a change in the designation of the owner
or operator under an operating or other similar agreement; or
C) a change pursuant to the action of the
owners of separate interests who designate an owner to be Permit Holder;
or
D) 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 UIC Well(s), including the right to
drill and/or operate said well(s) along with the full right and
responsibilities for operating the UIC Well(s).
3) The provisions of this subparagraph shall
not apply to the transfer of working interests not affecting the rights or
responsibilities of the Permit Holder.
4) The provisions of this subparagraph shall
not apply to transfers of UIC Well(s) abandoned or orphaned in accordance
General Rule G-1 or G-2. Transfers of UIC Wells deemed abandoned or orphaned
are subject to the transfer provisions in General Rule G-3.
5) Notification of a transfer shall be given
to the Director, or his designee, by the Current Permit Holder, on a form
prescribed by the Director, 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 General Rule B-13, 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.
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 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 or his designee, provided
the request was submitted within thirty (30) days of the actual transfer of the
UIC Well. However, 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, or his 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(s) pursuant to a
transfer shall apply for and must receive transfer approval from the Director,
or his designee, prior to operating the UIC Well(s) beyond the timeframe
specified in subparagraph t)(8) above.
10) Prior to the Director, or his designee,
approving the transfer request, the New Permit Holder shall provide the
required financial assurance, if applicable, in accordance with General Rule
B-2, and file the required organizational report, if applicable, in accordance
with General Rule B-13.
11) A
transfer to a New Permit Holder may be denied by the Director, or his designee,
if the New Permit Holder meets any of the conditions specified in subparagraph
q) above.
12) 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. 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) 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.
However, if the New Permit Holder, after being notified of the violation(s),
agrees in writing to the transfer approval including conditions to abate all
violations, the transfer may be approved by the Director, or his designee.
Failure to abate the violations within the time period specified by the
Director or his designee may result in revocation of the transfer approval in
accordance with subparagraph s) above, and/or other applicable enforcement
actions in accordance with General Rule A-5.
14) 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, or his designee, by the Current Permit Holder of the pending transfer
if the transfer is approved. However, if the transfer is denied by the Director
or his designee, the Current Permit Holder assumes all responsibility for the
violations caused by the New Permit Holder. Nothing in this subsection shall
affect the contractual rights and obligations between the person or entity
transferring the UIC Well(s) and the person or entity acquiring the UIC
Well(s).
15) The transfer approval
pursuant to this subparagraph 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. 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) The Director shall notify the Current and
New Permit Holder of the transfer approval or denial in writing. 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 General Rule A-2, A-3 and
other applicable hearing procedures. 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.
u)
Miscellaneous Provisions and Requirements for Class II Disposal or Class II
Commercial Disposal Wells Within General Rule B-43 Section c) lands.
1) Definitions:
a. "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 northeast (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 Rule; and
as updated for purposes of this Rule following notice and a hearing in
accordance with General Rule A-2.
b. "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 the general B-43 Section c) lands area.
2) Unless otherwise approved by the
Commission after notice and a hearing, no permit to drill, deepen, re-enter,
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
|
4N
|
12W
|
1-30, 35-36
|
4N
|
14W
|
1-2, 10-15, 23-25
|
4N
|
15W
|
4-9, 17-20, 30-31
|
5N
|
11W
|
25, 35-36
|
5N
|
15W
|
6
|
6N
|
10W
|
1-23, 26-34
|
6N
|
11W
|
1-4, 9-36
|
6N
|
14W
|
24-25, 36
|
6N
|
15W
|
3-9, 16-20, 29-31
|
7N
|
10W
|
1, 11-14, 22-27, 34-36
|
7N
|
14W
|
6-7
|
8N
|
9W
|
1-24, 26-35
|
8N
|
10W
|
25, 36
|
8N
|
14W
|
3-10, 15-21, 29-32
|
9N
|
9W
|
1-5, 7-36
|
9N
|
13W
|
1-23, 27-34
|
10N
|
9W
|
1-3, 9-17, 19-36
|
10N
|
12W
|
25, 33, 34, 36
|
10N
|
13W
|
17-22, 27-35
|
11N
|
9W
|
13, 23-27, 34-36
|
11N
|
12W
|
3)
Unless otherwise approved by the Commission after notice and a hearing, no
permit to drill or re-enter, 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 B-43 Section c) lands.
4)
Unless otherwise approved by the Commission after notice and a hearing, no
permit to deepen or re-complete 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 B-43 Section c) lands.
5) Unless otherwise approved by the
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 in any remaining B-43
Section 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.
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) The Applicant shall provide technical
information to the Director in support of the application. 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
miles (2) 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, 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.
(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)
RULE H-2:
WELL CONSTRUCTION,
OPERATING AND REPORTING REQUIREMENTS FOR CLASS II DISPOSAL
WELLS
a) No Class II
Disposal or EOR Well, as defined in General Rule H-1 a) 1) (hereinafter
referred to as "Class II Well" for purposes of this Rule), for which a permit
has been issued in accordance with General Rule H-1, shall be operated until
well internal mechanical integrity has been established in accordance with
sub-paragraph o) below, and an authority for initial commencement of injection
operations is issued by the Director.
b) The permit holder shall provide notice to
the 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. Any well servicing which requires the resetting of the packer shall
require an internal mechanical integrity test be run in accordance with
subparagraph o) below, prior to re-commencement of injection.
c) All well records for newly drilled Class
II Wells shall be submitted in accordance General Rule B-5. 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 $100 per well shall be due
each July 1st 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 General Rule H-1 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 250 feet
below the base of the lowermost USDW, and cement production casing to at least
250 feet above the proposed disposal zone; or
B) Set and cement surface casing fifty (50)
feet below the base of the lowermost formation utilized for a public water
system (see 40 CFR) in the area of the Class II Well, with a minimum of five
hundred (500) feet of surface casing required, and cement production casing
back to the surface.
3)
For existing wells converted to Class II Wells
A) Unless otherwise approved by the Director,
production casing in the existing well is required to be cemented to at least
250 feet above the proposed disposal zone. A cement bond (CBL), gamma ray (GR)
and density log (VDL) shall be required to verify the presence of the required
casing cement. The CBL should indicate at a minimum an 80% bond index over the
250 foot cemented interval.
B) If a
casing liner is required to provide well bore integrity above the required
production cementing requirements in subparagraph e) 3) A) above, the liner
must be set, at a minimum, below the cemented portion of the production casing
and cemented back to surface.
f) Tubing and packer requirements.
1) All injection shall be through tubing and
packer. The packer shall be placed no higher than 100 feet 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 500 feet below the base of the USDW.
2) If the tubing and packer cannot be set or
utilized in accordance with subsection f) 1) above, due to existing well
construction conditions, the Permit Holder may request the Director to
authorize an alternative packer setting depth or well construction. In
determining an alternative packer setting depth or alternative well
construction, the Director shall take into consideration the current
construction of the well, the depth of the USDWs and the nature of the
obstruction. If an alternative packer setting depth or well construction is
authorized, the Director may require additional or more frequent internal
mechanical integrity tests be performed on the well, or may require 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 24 hours
prior to the initial setting or any resetting of the packer in a Class II
Disposal Wells to enable an inspector to be present when the packer is
set.
g) The wellhead
shall be maintained in a leak-free condition, and must have a working pressure
guage in excess of the maximum discharge pressure of the pump. 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 General Rule H-1
h) 8).
i) No change shall be made
in the permitted injection zones unless the new zone is permitted in accordance
with General Rule H-1.
j) Injection
fluids shall be confined to the permitted injection zones. 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 subparagraph o) below.
l) Only Class II Fluids, as defined in
General Rule H-1 a) 3), and/or fresh water 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) The Permit Holder of each Class II Well
shall file a Quarterly Well Status Report on forms prescribed by the Director.
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. The report shall
include at a minimum:
1) Name and permit
number of the well;
2) Names of all
injection intervals;
3) Maximum
daily injection rates and pressures; and
4) Monthly volumes of fluid
injected.
o)
Establishment of Internal Mechanical Integrity.
1) Internal mechanical integrity must be
maintained at all times. 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. 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) 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. The Permit Holder shall contact the Regional
Office in which the well is located at least 48 hours prior to conducting the
test to enable an inspector to be present when the test is done.
i) Pressure Test
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 (50) psig for a period
of thirty (30) minutes. The casing-tubing annulus starting test pressure shall
not be less than three hundred (300) psig and may vary no more than ten (10)
percent of the starting test pressure during the test. The pressure at which
the test is to be performed shall be fifty (50) psig over the permitted
injection pressure, with a maximum of one thousand (1000) psig.
ii) Radioactive Tracer Survey Test
For those wells in which alternative well construction has been approved by the
Director in accordance with subparagraph f) 2) 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) 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. The necessary work shall be completed and an internal mechanical
integrity test successfully completed within ninety (90) days. 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 24 months shall be plugged or temporarily
abandoned in accordance with General Rule B-7.
(Source: new rule July 17, 2009; amended October 24, 2009;
amended June 16, 2019)
RULE
H-3:
WELL CONSTRUCTION, OPERATING AND REPORTING
REQUIREMENTS FOR CLASS II COMMERCIAL DISPOSAL WELLS
a) No Class II Commercial Disposal Well, as
defined in General Rule H-1 a) 2) (hereinafter referred to as "Class II
Commercial Disposal Well") for which a permit has been issued in accordance
with General Rule H-1, shall be operated until well internal mechanical
integrity has been established in accordance with sub-paragraph o) below, and
an authority for initial commencement of injection operations is issued by the
Director.
b) Notice shall be
provided to the 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. Any well servicing which requires the
resetting of the packer shall required an internal mechanical integrity test be
run in accordance with subparagraph o) below, prior to recommencement of
injection.
c) All well records for
newly drilled Class II Commercial Disposal Wells shall be submitted in
accordance General Rule B-5. 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 Commercial
Disposal Well, an annual fee of $100 per well shall be due each July
1st 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 General Rule H-1
a) 5) (hereinafter referred to as "USDW").
2) Existing wells shall be prohibited for
re-completion as a Class II Commercial Disposal Well unless the well had been
constructed at the time of original completion in accordance with subparagraph
e) 3) below.
3) Newly drilled Class
II Commercial Disposal Wells:
A) Set and
cement surface casing 250 feet below the base of the lowermost USDW, and cement
production casing to at least 500 feet above the proposed disposal zone;
or
B) Set and cement surface casing
fifty (50) feet below the base of the lowermost formation utilized for a public
water system (see 40 CFR) in the area of the Class II Commercial Disposal Well,
with a minimum of five hundred (500) feet of surface casing required, and
cement production casing back to the surface.
C) A cement bond (CBL), gamma ray (GR) and
density log (VDL) shall be required to verify the presence of the required
casing cement. The CBL should indicate at a minimum an 80% bond index over the
500 foot cemented interval.
f) Tubing and packer requirements.
1) All injection shall be through tubing and
packer. The packer shall be placed no higher than 100 feet 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 750 feet below the base of the
lowermost USDW.
2) The Permit
Holder shall contact the District Office in which the well is located at least
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) 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. 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
General Rule H-1 h) 8).
i) No
change shall be made in the permitted injection zones unless the new zone is
permitted in accordance with General Rule H-1.
j) Injection fluids shall be confined to the
permitted injection zones. 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 subparagraph o) below.
l) Only Class II Fluids, as defined in
General Rule H-1 a) 3), and/or fresh water can be injected into a Class II
Commercial Disposal 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 and an emergency telephone
number.
n) The Permit Holder of
each Class II Commercial Disposal Well shall file a Monthly Well Status Report
on forms prescribed by the Director. 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. The report shall include at a minimum:
1) Name and permit number of the
well;
2) Names of all injection
intervals;
3) Maximum daily
injection rates and pressures; and
4) Monthly volumes of fluid
injected.
5) In addition, each
Class II Commercial Disposal Well facility must keep an accurate log of each
shipment of fluids to be disposed. 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. A copy of this
log must accompany the above Monthly Well Status Report.
o) Establishment of Internal Mechanical
Integrity.
1) Internal mechanical integrity
must be maintained at all times. 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. 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) 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. 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. 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 (50) psig for
a period of thirty (30) minutes and may vary no more than ten (10) percent of
the starting test pressure during the test. The pressure at which the
mechanical integrity test is to be performed shall be fifty (50) psig over the
permitted injection pressure with a maximum of one thousand (1,000) psig. The
minimum test pressure shall be three hundred (300) psig.
B) 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. The necessary work shall be completed and an
internal mechanical integrity test successfully completed within ninety (90)
days. 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) All commercial facilities must have
restricted entry to all nonessential traffic. A lockable gate must be
maintained and shall be locked during all unmanned hours. Additionally, the
Director may require a fence to limit entry to the facility.
q) Permit Holders may be required to take
periodic samples of the injection fluid and have those samples analyzed at a
certified lab. Samples of the injection fluid may also be taken periodically by
a Commission representative. Samples will be checked for compliance with Class
II fluids as defined in General Rule H-1.
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 12 months shall be plugged in
accordance with General Rule B-7.