Current through Register Vol. 49, No. 2, February 2024
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.
GENERAL 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
and production allowable provisions of General Rule D-16 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.
RULE D-7 NATURALGAS TO BE
METERED
a)
Wellhead Production Meters:
1) For protection
of correlative rights of all parties, the operator of a natural gas well shall
meter or 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.
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; 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.
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 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.
