TITLE
19 NATURAL
RESOURCES AND WILDLIFE
CHAPTER
15 OIL
AND GAS
PART
27 VENTING
AND FLARING OF NATURAL GAS
19.15.27.1 ISSUING AGENCY: Oil Conservation Commission.
[19.15.27.1
NMAC – N, 05/25/2021]
19.15.27.2 SCOPE: 19.15.27 NMAC applies to persons engaged in
oil and gas exploration and production within New Mexico.
[19.15.27.2
NMAC – N, 05/25/2021]
19.15.27.3 STATUTORY AUTHORITY: 19.15.27 NMAC is adopted pursuant to the Oil
and Gas Act, Section 70-2-6, Section 70-2-11 and Section 70-2-12 NMSA 1978.
[19.15.27.3
NMAC – N, 05/25/2021]
19.15.27.4 DURATION: Permanent.
[19.15.27.4
NMAC – N, 05/25/2021]
19.15.27.5 EFFECTIVE DATE: May 25, 2021,
unless a later date is cited at the end of a section.
[19.15.27.5
NMAC – N, 05/25/2021]
19.15.27.6 OBJECTIVE: To regulate the venting and flaring of
natural gas from wells and production equipment and facilities to prevent waste
and protect correlative rights, public health, and the environment.
[19.15.27.6
NMAC – N, 05/25/2021]
19.15.27.7 DEFINITIONS: Terms shall have the meaning specified in
19.15.2 NMAC except as specified below.
B. “Average daily well production” means the number
derived by dividing the total volume of natural gas produced from a single well
in the preceding 12 months by the number of days that natural gas was produced
from the well during the same period.
C. “Average daily facility production” means, for a
facility receiving production from two or more wells, the number derived by
dividing the total volume of natural gas produced from all wells at the
facility during the preceding 12 months by the number of days, not to exceed
365, that natural gas was produced from one or more wells during the same
period.
D. “AVO” means audio, visual and olfactory.
E. “Completion operations” means
the period that begins with the initial perforation of the well in the
completed interval and concludes at the end of separation flowback.
F. “Drilling operations” means
the period that begins when a well is spud and concludes when casing and
cementing has been completed and casing slips have been set to install the tubing
head.
G. “Exploratory well" means a well located in a
spacing unit the closest boundary of which is two miles or more from:
(1) the outer boundary of a defined pool
that has produced oil or gas from the formation to which the well is or will be
completed; and
(2) an existing gathering pipeline as
defined in 19.15.28 NMAC.
H. “Emergency” means a
temporary, infrequent, and unavoidable event in which the loss of natural gas
is uncontrollable or necessary to avoid a risk of an immediate and substantial
adverse impact on safety, public health, or the environment, but does not
include an event arising from or related to:
(1) the operator’s failure to install
appropriate equipment of sufficient capacity to accommodate the anticipated or
actual rate and pressure of production;
(2) except as provided in Subparagraph
(4), the operator’s failure to limit production when the production rate
exceeds the capacity of the related equipment or natural gas gathering system
as defined in 19.15.28 NMAC, or exceeds the sales contract volume of natural
gas;
(3) scheduled maintenance;
(4) venting or flaring of natural gas
for more than eight hours after notification that is caused by an emergency,
unscheduled maintenance, or malfunction of a natural gas gathering system;
(5) the operator’s negligence;
(6) recurring equipment failure 4 or more
times within a single reporting area pursuant to Subsection A of 19.15.27.9
experienced by the operator within the preceding 30 days; or
(7) Four or more emergencies within a
single reporting area, pursuant to Subsection A of 19.15.27.9 NMAC, experienced
by the operator within the preceding 30 days, unless the division determines
the operator could not have reasonably anticipated the current event and it was
beyond the operator’s control.
I. “Flare” or “Flaring” means the controlled
combustion of natural gas in a device designed for that purpose.
J. “Flare stack” means a device equipped with a burner
used to flare natural gas.
K. “Gas-to-oil ratio (GOR)” for purposes of 19.15.27
NMAC means the ratio of natural gas to oil in the production stream expressed
in standard cubic feet of natural gas per barrel of oil.
L. “Initial flowback” means the period during
completion operations that begins with the onset of flowback and concludes when
it is technically feasible for a separator to function.
M. “Malfunction” means a sudden, unavoidable failure
or breakdown of equipment beyond the reasonable control of the operator that
substantially disrupts operations, but does not include a failure or breakdown
that is caused entirely or in part by poor maintenance, careless operation, or
other preventable equipment failure or breakdown.
N. “N2” means nitrogen gas.
O. “Natural gas” means a gaseous mixture of
hydrocarbon compounds, primarily composed of methane, and includes both
casinghead gas and gas as those terms are defined in 19.15.2 NMAC.
P. “Production operations” means the period that begins
on the earlier of 31 days following
the commencement of initial flowback or following completion of separation
flowback and concludes when the well is plugged and abandoned.
Q. “Producing in paying quantities” mean the production of a quantity of oil and gas that yields revenue
in excess of operating expenses.
R. “Separation flowback” means the period during
completion operations that begins when it is technically feasible for a separator
to function and concludes no later than 30 days after the commencement of initial
flowback.
S. “Vent” or “Venting” means the release of
uncombusted natural gas to the atmosphere.
[19.15.27.7
NMAC – N, 05/25/2021]
19.15.27.8 VENTING AND FLARING OF NATURAL
GAS:
A. Venting or flaring of natural gas during drilling,
completion, or production operations that constitutes waste as defined in
19.15.2 NMAC is prohibited. The operator has a general duty to maximize the
recovery of natural gas by minimizing the waste of natural gas through venting
and flaring. During drilling, completion and production
operations, the operator may vent or flare natural gas only as authorized in
Subsections B, C and D of 19.15.27.8 NMAC.
In all circumstances, the operator shall flare rather than vent natural
gas except when flaring is technically infeasible or would pose a risk to safe
operations or personnel safety, and venting is a safer alternative than
flaring.
B. Venting and flaring during
drilling operations.
(1) The
operator shall capture or combust natural gas if technically feasible using
best industry practices and control technologies.
(2) A
properly-sized flare stack shall be
located at a minimum of 100 feet from the nearest surface hole location unless
otherwise approved by the division.
(3) In
an emergency or malfunction, the operator may vent natural gas to avoid a risk
of an immediate and substantial adverse impact on safety, public health, or the
environment. The operator shall report natural
gas vented or flared during an emergency or malfunction to the division
pursuant to Paragraph (1) of Subsection G of 19.15.27.8 NMAC.
C. Venting and flaring during completion or recompletion operations.
(1) During
initial flowback, the operator shall route flowback fluids into a completion or
storage tank and, if technically feasible under the applicable well conditions,
flare rather than vent and commence operation of a separator as soon as it is
technically feasible for a separator to function.
(2) During
separation flowback, the operator shall capture and route natural gas from the
separation equipment:
(a) to a gas flowline or collection
system, reinject into the well, or use on-site as a fuel source or other
purpose that a purchased fuel or raw material would serve; or
(b) to a flare if routing the natural
gas to a gas flowline or collection system, reinjecting it into the well, or using
it on-site as a fuel source or other purpose that a purchased fuel or raw
material would serve would pose a risk to safe operation or personnel safety.
(3) If
natural gas does not meet gathering pipeline quality specifications, the
operator may flare the natural gas for 60 days or until the natural gas meets
the pipeline quality specifications, whichever is sooner,
provided that:
(a) a properly-sized flare stack is
equipped with an automatic igniter or continuous pilot;
(b) the operator analyzes
natural gas samples twice per week;
(c) the operator routes the natural gas
into a gathering pipeline as soon as the pipeline specifications are met; and
(d) the operator provides the pipeline
specifications and natural gas analyses to the division upon request.
D. Venting and flaring during production operations. The operator shall not vent or flare natural
gas except:
(1) during
an emergency or malfunction;
(2) to unload or clean-up liquid holdup
in a well to atmospheric pressure, provided
(a) the operator does not vent after the
well achieves a stabilized rate and pressure;
(b) for liquids unloading by manual
purging, the operator remains present on-site until the end of unloading or
posts at the well site the contact information of the personnel conducting the
liquids unloading operation and ensures that personnel remains within 30
minutes’ drive time of the well being unloaded until the end of unloading, takes
all reasonable actions to achieve a stabilized rate and pressure at the
earliest practical time and takes reasonable actions to minimize venting to the
maximum extent practicable;
(c) for a well equipped with a plunger lift system or an
automated control system, the operator optimizes the system to minimize the
venting of natural gas; or
(d) during downhole well maintenance,
only when the operator uses a workover rig, swabbing rig, coiled tubing unit or
similar specialty equipment and minimizes the venting of natural gas to the
extent that it does not pose a risk to safe operations and personnel safety and
is consistent with best management practices;
(3) during the first 12 months of
production from an exploratory well, or as extended by the division for good
cause shown, provided:
(a) the operator proposes and the division
approves the well as an exploratory well;
(b) the operator is in compliance with
its statewide gas capture requirements; and
(c) within 15 days of determining an exploratory
well is capable of producing in paying quantities, the operator submits an
updated form C‑129 to the division, including a natural gas management
plan and timeline for connecting the well to a natural gas gathering system or
as otherwise approved by the division; or
(4) during the following activities unless
prohibited by applicable state or federal law, rule, or regulation for the
emission of hydrocarbons and volatile organic compounds:
(a) gauging or sampling a storage
tank or other low-pressure production vessel;
(b) loading out liquids from a storage
tank or other low-pressure production vessel to a transport vehicle;
(c) repair and maintenance, including
blowing down and depressurizing production equipment to perform repair and
maintenance;
(d) normal operation of a gas-activated
pneumatic controller or pump;
(f) normal operation of dehydration
units and amine treatment units;
(g) normal operations of compressors,
compressor engines, and turbines;
(h) normal operations of valves,
flanges and connectors that is not the result of inadequate equipment design or
maintenance;
(i) a
bradenhead test;
(j) a packer leakage test;
(k) a production test lasting less
than 24 hours unless the division requires or approves a longer test period;
(l) when natural gas does not meet the gathering
pipeline specifications, provided the operator analyzes natural gas samples
twice per week to determine whether the specifications have been achieved, routes
the natural gas into a gathering pipeline as soon as the pipeline specifications
are met and provides the pipeline specifications and natural gas analyses to
the division upon request; or
(m) Commissioning of pipelines, equipment,
or facilities only for as long as necessary to purge introduced impurities from
the pipeline or equipment.
E. Performance standards
(1) The operator shall design completion
and production separation equipment and storage tanks for maximum anticipated throughput
and pressure to minimize waste.
(2) The operator of a permanent storage
tank associated with production operations that is routed to a flare or control
device installed after May 25, 2021, shall equip the storage tank with an
automatic gauging system that reduces the venting of natural gas.
(3) The operator shall combust natural
gas in a flare stack that is properly sized and designed to ensure proper
combustion efficiency.
(a) A flare stack installed or replaced
after May 25, 2021, shall be equipped with an automatic ignitor or continuous
pilot.
(b) A flare stack installed before May
25, 2021, shall be retrofitted with an automatic ignitor, continuous pilot, or
technology that alerts the operator that the flare may have malfunctioned no
later than 18 months after May 25, 2021.
(c) A flare
stack located at a well or facility, with an average daily production of equal
to or less than 60,000 cubic feet of natural gas shall be equipped with an
automatic ignitor or continuous pilot if the flare stack is replaced after May
25, 2021.
(4) A flare stack constructed after May
25, 2021, shall be securely anchored and located at least 100 feet from the
well and storage tanks unless otherwise approved by the division.
(5) The operator shall conduct an AVO
inspection on the frequency specified below to confirm that all production
equipment is operating properly and there are no leaks or releases except as
allowed in Subsection D of 19.15.27.8 NMAC.
(a) During an AVO inspection the operator
shall inspect all components, including flare stacks, thief hatches, closed
vent systems, pumps, compressors, pressure relief devices, valves, lines,
flanges, connectors, and associated piping to identify defects, leaks, and
releases by:
(i) a comprehensive external visual
inspection;
(ii) listening for pressure and liquid leaks;
and
(iii) smelling for unusual and strong odors.
(b) The operator shall conduct an AVO
inspection weekly:
(i) during the first year of
production; and
(ii) on a well or facility with an average
daily production greater than 60,000 cubic feet of natural gas.
(c) The operator shall conduct an AVO
inspection weekly if the operator is on site, and in no case less than once per
calendar month with at least 20 calendar days between inspections:
(i) on a well or facility with an
average daily production equal to or less than 60,000 cubic feet of natural gas;
and
(ii) on shut‑in, temporarily
abandoned, or inactive wells.
(d) The operator shall make and keep a
record of an AVO inspection for not less than five years and make such record
available for inspection by the division upon request.
(6) Subject to the division’s prior
written approval, the operator may use a remote or automated monitoring
technology to detect leaks and releases in lieu of an AVO inspection.
(7) for
facilities constructed after May 25, 2021, facilities shall be designed to
minimize waste;
(8) Operators have an obligation to
minimize waste and shall resolve emergencies as quickly and safely as is feasible.
F. Measurement or estimation of vented
and flared natural gas.
(1) The operator shall measure or
estimate the volume of natural gas that it vents, flares, or beneficially uses
during drilling, completion, and production operations regardless
of the reason or authorization for such venting or flaring.
(2) The operator shall install equipment to
measure the volume of natural gas flared from existing process piping or a flowline
piped from equipment such as high pressure separators, heater treaters, or vapor
recovery units associated with a well or facility associated with a well authorized
by an APD issued after May 25, 2021, that has an average daily production
greater than 60,000 cubic feet of natural gas.
(3) Measuring equipment shall conform to
an industry standard such as American Petroleum Institute (API) Manual of
Petroleum Measurement Standards (MPMS) Chapter 14.10 Measurement of Flow to
Flares.
(4) Measuring equipment shall not be
designed or equipped with a manifold that allows the diversion of natural gas
around the metering element except for the sole purpose of inspecting and
servicing the measurement equipment.
(5) If metering is not practicable due to
circumstances such as low flow rate or low pressure venting and flaring, the
operator may estimate the volume of vented or flared natural gas using a
methodology that can be independently verified.
(6) For a well that does not require
measuring equipment, the operator shall estimate the volume of vented and
flared natural gas based on the result of an annual GOR test for that well
reported on form C‑116 to allow the division to independently verify the
volume and rate of the flared natural gas.
(7) The operator shall install measuring
equipment whenever the division determines that metering is practicable or the
existing measuring equipment or GOR test is not sufficient to measure the
volume of vented and flared natural gas.
G. Reporting of vented or flared natural gas.
(1) Venting
or flaring caused by an emergency, a malfunction or of long duration.
(a) The operator shall notify the
division of venting or flaring that exceeds 50 MCF in volume and either results
from an emergency or malfunction, or lasts eight hours or more cumulatively
within any 24-hour period from a single event by filing a form C-129 in lieu of a C-141, except as provided by Subparagraph (d)
of Paragraph (1) of Subsection G of 19.15.27.8 NMAC, with the division as
follows:
(i) for venting or flaring that equals
or exceeds 50 MCF but less than 500 MCF from a single event, notify the division
in writing by filing a form C-129 no later than 15 days following discovery or
commencement of venting or flaring;
(ii) for venting or flaring that equals or
exceeds 500 MCF or otherwise qualifies as a major release as defined in
19.15.29.7 NMAC from a single event, notify the division verbally or by e-mail
as soon as possible and no later than 24 hours following discovery or
commencement of venting or flaring and provide the information required in form
C-129. No later than 15 days following
the discovery or commencement of venting or flaring, the operator shall file a
form C-129 that verifies, updates, or corrects the verbal or e-mail
notification; and
(iii) no later than 15 days following the
termination of venting or flaring, notify the division by filing a form C-129.
(b) The operator shall provide and
certify the accuracy of the following information in the form C-129:
(i) operator’s name;
(ii) name and type of facility;
(iii) equipment involved;
(iv) compositional analysis of vented or
flared natural gas that is representative of the well or facility;
(v) date(s) and time(s) that venting or
flaring was discovered or commenced and terminated;
(vi) measured or estimated volume of vented
or flared natural gas;
(vii) cause and nature of venting or flaring;
(viii) steps taken to limit the duration and
magnitude of venting or flaring; and
(ix) corrective actions taken to eliminate
the cause and recurrence of venting or flaring.
(c) At the division’s request, the
operator shall provide and certify additional information by the specified
date.
(2) Monthly reporting of vented and flared natural gas. For each well or
facility at which venting or flaring occurred, the operator shall separately
report the volume of vented natural gas and volume of flared natural gas for
each month in each category listed below. Beginning October 1, 2021, the operator shall gather
data for quarterly reports in a format specified by the division and submit by February
15, 2022 for the fourth quarter and May 15, 2022 for the first quarter. Beginning April 2022, the operator shall
submit a form C-115B monthly on or before the 15th
day of the second month following the month in which it vented or flared
natural gas. The operator shall
specify whether it estimated or measured each reported volume. In
filing the initial report, the operator shall provide the methodology (measured
or estimated using calculations and industry standard factors) used to report
the volumes and shall report changes in the methodology on future forms. The operator shall make and keep records of
the measurements and estimates, including records showing how it calculated the
estimates, for no less than five years and make such records available for
inspection by the division upon request.
The categories are:
(a) emergency;
(b) non-scheduled maintenance or
malfunction, including the abnormal operation of equipment;
(c) routine repair and maintenance,
including blowdown and depressurization;
(d) routine downhole maintenance,
including operation of workover rigs, swabbing rigs, coiled tubing units and
similar specialty equipment;
(e) manual liquid unloading;
(f) storage tanks;
(g) insufficient availability or capacity
in a natural gas gathering system during the separation phase of completion
operations or production operations;
(h) natural gas
that is not suitable for transportation or processing because:
(i) N2,
H2S, or CO2 concentrations do not meet gathering pipeline
quality specifications; or
(ii) O2
concentrations do not meet gathering pipeline quality specifications except
during commissioning of pipelines, equipment, or facilities pursuant to Subparagraph
(l) of Paragraph (4) of Subsection D of 19.15.27.8 NMAC, except as otherwise
approved by the division;
(i) venting as a result of normal
operation of pneumatic controllers and pumps, unless the operator vents or
flares less than 500,000 cubic feet per year of natural gas;
(j) improperly closed or maintained thief
hatches;
(k) venting or flaring in excess of
eight hours that is caused by an emergency, unscheduled maintenance or
malfunction of a natural gas gathering system as defined in 19.15.28 NMAC;
(l) venting and flaring from an exploratory
well; and
(m) other surface
waste as defined in Subparagraph (b) of Paragraph (1) of Subsection W of 19.15.2.7
NMAC that is not described above.
(a) To calculate the lost natural gas on
a volumetric basis, the operator shall deduct the volume of natural gas sold,
used for beneficial use, vented or flared during an emergency, and vented or flared because it was not
suitable for transportation or processing due to N2, H2S,
or CO2 concentrations, vented as a result of normal operation of
pneumatic controllers and pumps if reported pursuant to Subparagraph (i) of
Paragraph (2) of Subsection G of 19.15.27.8 NMAC, or vented or flared from an
exploratory well with division approval from the natural gas produced.
(b) To calculate the natural gas captured
on a percentage basis, the operator shall deduct the volume of lost gas
calculated in Subparagraph (a) of Paragraph (3) of Subsection G of 19.15.27.8
NMAC from the total volume of natural gas produced and divide by the total
volume of natural gas produced.
(4) Beginning June 2022, the operator
shall provide a copy of the C-115B to the New Mexico State Land Office for a
well or facility in which the state owns a royalty interest, and the operator
shall notify all royalty interest owners of their ability to obtain the
information from the division’s website at the time the initial C-115B is
filed.
(5) Upon the New Mexico environment
department’s request, the operator shall promptly provide a copy of any form
filed pursuant to 19.15.27 NMAC.
[19.15.27.8
NMAC – N, 05/25/2021]
19.15.27.9 STATEWIDE NATURAL GAS CAPTURE
REQUIREMENTS:
A. Statewide natural gas capture requirements. Commencing April 1, 2022, the operator shall
reduce the annual volume of vented and flared natural gas in order to capture no
less than ninety-eight percent of the natural gas produced from its wells in
each of two reporting areas, one north and one south of the Township 10 North line,
by December 31, 2026. The division shall
calculate and publish on the division’s website each operator’s baseline
natural gas capture rate based on the operator’s fourth
quarter 2021 and first quarter 2022 quarterly reports as per Paragraph (2) of Subsection
G of 19.15.27.8 NMAC. In each
calendar year between January 1, 2022 and December 31, 2026, the operator shall
increase its annual percentage of natural gas captured in each reporting area
in which it operates based on the following formula: (baseline loss rate minus
two percent) divided by five, except that for 2022 only, an operator’s
percentage of natural gas captured shall not be less than seventy-five percent of
the annual gas capture percentage increase (2022 baseline loss rate minus two
percent divided by five times 0.75), and the balance shall be captured in 2023.
(1) The following table provides examples
of the formula based on a range of baseline natural gas capture rates.
|
Baseline
Natural Gas Capture Rate |
Minimum
Required Annual Natural Gas Capture Percentage Increase |
|
90-98% |
0-1.6% |
|
80-89% |
>1.6-3.6% |
|
70-79% |
>3.6-5.6% |
|
0-69% |
>5.6-19.6% |
(2) If the operator’s baseline capture
rate is less than sixty percent, the operator shall submit by the specified
date to the division for approval a plan to meet the minimum required annual
capture percentage increase.
(3) An operator’s acquisition or sale of one or more wells from another
operator shall not affect its annual natural gas capture requirements. No later 60 days following the acquisition or
sale, the operator may file a written request to the division requesting to
modify its gas capture percentage requirements for good cause based on its
acquisition or sale. The division may
approve, approve with conditions, or deny the request in its sole discretion.
(4) No later than March 30 following
the reporting year, an operator that has not met its annual natural gas
capture requirement for the previous year shall submit
to the division a compliance plan demonstrating its ability to comply with its annual
gas capture requirement for the current year. If the division determines, after a reasonable
opportunity to meet with the operator, that the
compliance plan does not demonstrate the operator’s ability to comply with its
annual gas capture requirement for the current year the operator’s approved
APDs for wells that have not been spud shall be suspended pending a division
hearing to be held no later than 30 days after the determination. Nothing in
this subparagraph shall prevent the division from taking any other action
authorized by law for the operator’s failure to comply with its annual gas
capture requirement, including shutting in wells and assessing civil penalties.
B. Accounting.
No later than February 28 of each year beginning
in 2023, the operator shall submit a report certifying compliance with its
statewide gas capture requirements. The
operator shall determine compliance with its statewide gas capture requirements
by deducting any ALARM credits approved pursuant to this subsection from the
aggregated volume of lost gas calculated for each month during the preceding
year pursuant to Subparagraph (a) of Paragraph (3) of Subsection G of
19.15.27.8 NMAC, deducting that aggregated volume of lost gas from the
aggregated volume of natural gas produced for each month during the preceding
year, and dividing that volume by the aggregated volume of natural gas produced
for each month during the preceding year.
(a) isolated the leak or release within
48 hours following field verification;
(b) repaired the leak or release within
15 days following field verification or another date approved by the division;
(c) timely notified the division by
filing a form C‑129 or form C‑141; and
(d) used ALARM
monitoring technology as a routine and on‑going aspect of its
waste-reduction practices.
(i) For
discrete waste-reduction practices such as aerial methane monitoring, the
operator must use the technology at least twice per year; and
(ii) for
waste‑reduction practices such as automated emissions monitoring systems
that operate routinely or continuously, the division will determine the
required frequency of use.
(e) The
division shall publish a list of division-approved ALARM technologies on the division’s
website.
(2) An operator may file an application
with the division for a credit against its volume of lost natural gas that identifies:
(a) the ALARM technology used to discover the leak or release;
(b) the dates on which the leak or release
was discovered, field-verified, isolated and repaired;
(c) the method used to measure or
estimate the volume of natural gas leaked or released which method shall be
consistent with Subsection F of 19.15.27.8 NMAC;
(d) a description and the date of each
action taken to isolate and repair the leak or release;
(e) visual documentation or other
verification of discovery, isolation and repair of the leak or release;
(f) a certification that the operator
did not know or have reason to know of the leak or release before discovery
using ALARM technology; and
(g) a description of how the operator used
ALARM technology as a routine and on‑going aspect of its waste‑reduction
practices.
(3) For each leak or release reported by
an operator that meets the requirements of Paragraphs (3) and (4) of Subsection
B of 29.15.28.10 NMAC, the division, in its sole discretion, may approve a
credit that the operator can apply against its reported volume of lost natural
gas as follows:
(a) a credit of forty percent of the
volume of natural gas discovered and isolated within 48 hours of discovery and timely repaired;
(b) an additional credit of twenty
percent if the operator used ALARM technology no less than once per calendar
quarter as a routine and on‑going aspect of its waste‑reduction
practices.
(4) A division‑approved ALARM
credit shall:
(a) be used only by the operator who
submitted the application pursuant to Paragraph (4) of Subsection B of 29.15.27.10
NMAC;
(b) not be transferred to or used by
another operator, including a parent, subsidiary, related entity, or person
acquiring the well;
(c) be used only once; and
(d) expire 24 months after division
approval.
(5) The division will publish a list of
approved ALARM technology.
C. Third‑party
verification. The division may request that an operator retain a third
party to verify any data or information collected or reported pursuant to this
Part, make recommendations to correct or improve the collection and reporting
of data and information, submit a report of the verification and
recommendations to the division by the specified date, and implement the
recommendations in the manner approved by the division. If the division and the operator cannot reach agreement on
the division’s request, the operator may file an application for hearing before
the division. The operator, at its own expense, shall retain a third party
approved by the division to conduct the activities agreed to by the division
and the operator or ordered by the division following a hearing.
D. Natural gas management plan.
(a) the operator’s name and OGRID number;
(b) the name, API number, location and
footage;
(c) the anticipated dates of drilling,
completion and first production;
(d) a description of operational best
practices that will be used to minimize venting during active and planned
maintenance; and
(e) the anticipated volumes of liquids
and gas production and a description of how separation equipment will be sized
to optimize gas capture.
(2) Beginning April 1, 2022, an
operator that, at the time it submits an APD for a new or recompleted well is, cumulatively
for the year, not in compliance with its baseline natural gas capture rate for the applicable
reporting area if the APD is submitted on or after April 1, 2022 or its natural
gas capture requirement for the previous year if the APD is submitted in 2023
or after shall also include the following information in the
natural gas management plan:
(a) the anticipated volume of produced natural
gas in units of MCFD for the first year of production;
(b) the existing natural gas gathering
system the operator has contracted or anticipates contracting with to gather
the natural gas, including:
(i) the name of the natural gas
gathering system operator;
(ii) the name and location of the natural
gas gathering system;
(iii) a map of the well location and the
anticipated pipeline route connecting the production operations to the existing
or planned interconnect of the natural gas gathering system.; and
(iv) the maximum daily capacity of the segment
or portion of the natural gas gathering system to which the well will be
connected; and
(c) the operator’s plans for
connecting the well to the natural gas gathering system, including:
(i) the anticipated date on which the
natural gas gathering system will be available to gather the natural gas
produced from the well;
(ii) whether the natural gas gathering
system has or will have capacity to gather the anticipated natural gas
production volume from the well prior to the date of first production; and
(iii) whether the operator anticipates the
operator’s existing well(s) connected to the same segment or portion of the natural
gas gathering system, referenced in Item (iv) of Subparagraph (b) of Paragraph
(2) of Subsection D or 19.15.27.9 NMAC will continue to be able to meet anticipated
increases in line pressure caused be the well and the operator’s plan to manage
production in response to the increased line pressure.
(3) The operator may assert confidentiality
for information specified in Paragraph (2) of Subsection D of 19.15.27.9 NMAC
pursuant to Section 71-2-8 NMSA 1978.
(4) The operator shall certify that it
has determined based on the available information at the time of submitting the
natural gas management plan either:
(a) it will be able to connect the well
to a natural gas gathering system in the general area with sufficient capacity
to transport one hundred percent of the volume of natural gas the operator
anticipates the well will produce commencing on the date of first production,
taking into account the current and anticipated volumes of produced natural gas
from other wells connected to the pipeline gathering system; or
(b) it will not be able to connect to a
natural gas gathering system in the general area with sufficient capacity to
transport one hundred percent of the volume of natural gas the operator
anticipates the well will produce commencing on the date of first production,
taking into account the current and anticipated volumes of produced natural gas
from other wells connected to the pipeline gathering system.
(5) If the operator determines it will
not be able to connect a natural gas gathering system in the general area with
sufficient capacity to transport one hundred percent of the anticipated volume
of natural gas produced on the date of first production from the well, the
operator shall either shut-in the well until the operator submits the
certification required by Paragraph (4) of Subsection D of 19.15.27.9 NMAC or submit
a venting and flaring plan to the division that evaluates and selects one or
more of the potential alternative beneficial uses for the natural gas until a natural
gas gathering system is available, including:
(a) power generation on lease;
(b) power generation for grid;
(c) compression on lease;
(d) liquids removal on lease;
(e) reinjection for underground storage;
(f) reinjection for temporary storage;
(g) reinjection for enhanced oil
recovery;
(h) fuel cell production; and
(i) other alternative beneficial uses
approved by the division.
(6) If, at any time after the operator
submits the natural gas management plan and before the well is spud:
(a) the operator becomes aware that the
natural gas gathering system it planned to connect the well to has become
unavailable or will not have capacity to transport one hundred percent of the
production from the well, no later than 20 days after becoming aware of such
information, the operator shall submit for the division’s approval a new or
revised venting and flaring plan containing the information specified in Paragraph
(5) of Subsection D of 19.15.27.9 NMAC; and
(b) the operator becomes
aware that it has, cumulatively for the year, become out of compliance with its
baseline natural gas capture rate or natural gas capture requirement, no later
than 20 days after becoming aware of such information, the operator shall
submit for the division’s approval a new or revised natural gas management plan
for each well it plans to spud during the next 90 days containing the
information specified in Paragraph (2) of Subsection D of 19.15.27.9 NMAC, and shall file
an update for each plan until the operator is back in compliance with its
baseline natural gas capture rate or natural gas capture requirement.
(7) The division may deny the APD or conditionally
approve the APD if the operator does not make a certification, fails to submit
an adequate venting and flaring plan, which includes alternative beneficial
uses for the anticipated volume of natural gas produced, or if the division
determines that the operator will not have adequate natural gas takeaway
capacity at the time a well will be spud.
[19.15.27.9 NMAC – N, 05/25/2021]
History
of 19.15.27 NMAC: [RESERVED]