Title 43—Public Lands: Interior--Volume 1
PART 3170—ONSHORE OIL AND GAS PRODUCTION
§ 3176.8   Drilling/completion/workover requirements.
(a) General. (1) A copy of the H 2 S Drilling Operations Plan shall be available during operations at the well site, beginning when the operation is subject to the terms of this subpart ( i.e., 3 days or 500 feet of known or probable H 2 S zone).
Table 1 to § 3176.8 (a)(1)
(2) Initial H 2 S training shall be completed and all H 2 S related safety equipment shall be installed, tested, and operational when drilling reaches a depth of 500 feet above, or 3 days prior to penetrating (whichever comes first) the first zone containing or reasonably expected to contain H 2 S. A specific H 2 S operations plan for completion and workover operations will not be required for approval. For completion and workover operations, all required equipment and warning systems shall be operational and training completed prior to commencing operations.
Table 2 to § 3176.8 (a)(2)
(3) If H 2 S was not anticipated at the time the APD was approved, but is encountered in excess of 100 ppm in the gas stream, the following measures shall be taken:
(i) The operator shall immediately ensure control of the well, suspend drilling ahead operations (unless detrimental to well control), and obtain materials and safety equipment to bring the operations into compliance with the applicable provisions of this subpart.
Table 3 to § 3176.8 (a)(3)(i)
(ii) The operator shall notify the authorized officer of the event and the mitigating steps that have or are being taken as soon as possible, but no later than the next business day. If said notification is subsequent to actual resumption of drilling operations, the operator shall notify the authorized officer of the date that drilling was resumed no later than the next business day.
Table 4 to § 3176.8 (a)(3)(ii)
(iii) It is the operator's responsibility to ensure that the applicable requirements of this subpart have been met prior to the resumption of drilling ahead operations. Drilling ahead operations will not be suspended pending receipt of a written H 2 S Drilling Operations Plan(s) and, if necessary, Public Protection Plan(s) provided that complete copies of the applicable Plan(s) are filed with the authorized officer for approval within 5 business days following resumption of drilling ahead operations.
Table 5 to § 3176.8 (a)(3)(iii)
(b) Locations. (1) Where practical, 2 roads shall be established, 1 at each end of the location, or as dictated by prevailing winds and terrain. If an alternate road is not practical, a clearly marked footpath shall be provided to a safe area. The purpose of such an alternate escape route is only to provide a means of egress to a safe area.
Table 6 to § 3176.8 (b)(1)
(2) The alternate escape route shall be kept passable at all times.
Table 7 to § 3176.8 (b)(2)
(3) For workovers, a secondary means of egress shall be designated.
Table 8 to § 3176.8 (b)(3)
(c) Personnel protection —(1) Training program. The operator shall ensure that all personnel who will be working at the wellsite will be properly trained in H 2 S drilling and contingency procedures in accordance with the general training requirements outlined in API RP-49, Section 2 (incorporated by reference, see § 3176.11). (The use of later editions of API RP-49 is deemed to comply with the requirements of this paragraph (c)(1).) The operator also shall ensure that the training will be accomplished prior to a well coming under the terms of this subpart ( i.e., 3 days or 500 feet of known or probable H 2 S zone). In addition to the requirements of API RP-49, a minimum of an initial training session and weekly H 2 S and well control drills for all personnel in each working crew shall be conducted. The initial training session for each well shall include a review of the site-specific Drilling Operations Plan and, if applicable, the Public Protection Plan.
Table 9 to § 3176.8 (c)(1)
(i) All training sessions and drills shall be recorded on the driller's log or its equivalent.
Table 10 to § 3176.8 (c)(1)(i)
(ii) For drilling/completion/workover wells, at least 2 briefing areas shall be designated for assembly of personnel during emergency conditions, located a minimum of 150 feet from the well bore, and 1 of the briefing areas shall be upwind of the well at all times. The briefing area located most normally upwind shall be designated as the “primary briefing area.”
Table 11 to § 3176.8 (c)(1)(ii)
(iii) One person (by job title) shall be designated and identified to all on-site personnel as the person primarily responsible for the overall operation of the on-site safety and training programs.
Table 12 to § 3176.8 (c)(1)(iii)
(2) Protective equipment. (i) The operator shall ensure that proper respiratory protection equipment program is implemented, in accordance with ANSI Z88.2-1992 (incorporated by reference, see § 3176.11). (The use of ANSI Z88.2-1980 is deemed to comply with the requirements of this paragraph (d)(2)(i).) Proper protective breathing apparatus shall be readily accessible to all essential personnel on a drilling/completion/workover site. Escape and pressure-demand type working equipment shall be provided for essential personnel in the H 2 S environment to maintain or regain control of the well. For pressure-demand type working equipment those essential personnel shall be able to obtain a continuous seal to the face with the equipment. The operator shall ensure that service companies have the proper respiratory protection equipment when called to the location. Lightweight, escape-type, self-contained breathing apparatus with a minimum of 5-minute rated supply shall be readily accessible at a location for the derrickman and at any other location(s) where escape from an H 2 S contaminated atmosphere would be difficult.
Table 13 to § 3176.8 (c)(2)(i)
(ii) Storage and maintenance of protective breathing apparatus shall be planned to ensure that at least 1 working apparatus per person is readily available for all essential personnel.
Table 14 to § 3176.8 (c)(2)(ii)
(iii) The following additional safety equipment shall be available for use:
(A) Effective means of communication when using protective breathing apparatus;
(B) Flare gun and flares to ignite the well; and
(C) Telephone, radio, mobile phone, or any other device that provides communication from a safe area at the rig location, where practical.
Table 15 to § 3176.8 (c)(2)(iii)
(3) H 2 S detection and monitoring equipment. (i) Each drilling/completion site shall have an H 2 S detection and monitoring system that automatically activates visible and audible alarms when the ambient air concentration of H 2 S reaches the threshold limits of 10 and 15 ppm in air, respectively. The sensors shall have a rapid response time and be capable of sensing a minimum of 10 ppm of H 2 S in ambient air, with at least 3 sensing points located at the shale shaker, rig floor, and bell nipple for a drilling site and the cellar, rig floor, and circulating tanks or shale shaker for a completion site. The detection system shall be installed, calibrated, tested, and maintained in accordance with the manufacturer's recommendations.
Table 16 to § 3176.8 (c)(3)(i)
(ii) All tests of the H 2 S monitoring system shall be recorded on the driller's log or its equivalent.
Table 17 to § 3176.8 (c)(3)(ii)
(iii) For workover operations, 1 operational sensing point shall be located as close to the wellbore as practical. Additional sensing points may be necessary for large and/or long-term operations.
Table 18 to § 3176.8 (c)(3)(iii)
(4) Visible warning system. (i) Equipment to indicate wind direction at all times shall be installed at prominent locations and shall be visible at all times during drilling operations. At least 2 such wind direction indicators ( i.e., windsocks, windvanes, pennants with tailstreamers, etc.) shall be located at separate elevations ( i.e., near ground level, rig floor, and/or treetop height). At least 1 wind direction indicator shall be clearly visible from all principal working areas at all times so that wind direction can be easily determined. For completion/workover operations, 1 wind direction indicator shall suffice, provided it is visible from all principal working areas on the location. In addition, a wind direction indicator at each of the 2 briefing areas shall be provided if the wind direction indicator(s) previously required in this paragraph (c)(4)(i) are not visible from the briefing areas.
Table 19 to § 3176.8 (c)(4)(i)
(ii) At any time when the terms of this subpart are in effect, operational danger or caution sign(s) shall be displayed along all controlled accesses to the site.
Table 20 to § 3176.8 (c)(4)(ii)
(iii) Each sign shall be painted a high visibility red, black and white, or yellow with black lettering.
Table 21 to § 3176.8 (c)(4)(iii)
(iv) The sign(s) shall be legible and large enough to be read by all persons entering the well site and be placed a minimum of 200 feet but no more than 500 feet from the well site and at a location which allows vehicles to turn around at a safe distance prior to reaching the site.
Table 22 to § 3176.8 (c)(4)(iv)
(v) The sign(s) shall read: “DANGER—POISON GAS—HYDROGEN SULFIDE,” and in smaller lettering: “Do Not Approach If Red Flag is Flying” or equivalent language if approved by the authorized officer. Where appropriate, bilingual or multilingual danger sign(s) shall be used.
Table 23 to § 3176.8 (c)(4)(v)
(vi) All sign(s) and, when appropriate, flag(s) shall be visible to all personnel approaching the location under normal lighting and weather conditions.
Table 24 to § 3176.8 (c)(4)(vi)
(vii) When H 2 S is detected in excess of 10 ppm at any detection point, red flag(s) shall be displayed.
Table 25 to § 3176.8 (c)(4)(vii)
(5) Warning system response. When H 2 S is detected in excess of 10 ppm at any detection point, all non-essential personnel shall be moved to a safe area and essential personnel ( i.e., those necessary to maintain control of the well) shall wear pressure-demand type protective breathing apparatus. Once accomplished, operations may proceed.
Table 26 to § 3176.8 (c)(5)
(d) Operating procedures and equipment —(1) General/operations. Drilling/completion/workover operations in H 2 S areas shall be subject to the following requirements:
(i) If zones containing in excess of 100 ppm of H 2 S gas are encountered while drilling with air, gas, mist, other nonmud circulating mediums or aerated mud, the well shall be killed with a water- or oil-based mud and mud shall be used thereafter as the circulating medium for continued drilling.
Table 27 to § 3176.8 (d)(1)(i)
(ii) A flare system shall be designed and installed to safely gather and burn H 2 S-bearing gas.
Table 28 to § 3176.8 (d)(1)(ii)
(iii) Flare lines shall be located as far from the operating site as feasible and in a manner to compensate for wind changes. The flare line(s) mouth(s) shall be located not less than 150 feet from the wellbore unless otherwise approved by the authorized officer. Flare lines shall be straight unless targeted with running tees.
Table 29 to § 3176.8 (d)(1)(iii)
(iv) The flare system shall be equipped with a suitable and safe means of ignition.
Table 30 to § 3176.8 (d)(1)(iv)
(v) Where noncombustible gas is to be flared, the system shall be provided supplemental fuel to maintain ignition.
Table 31 to § 3176.8 (d)(1)(v)
(vi) At any wellsite where SO 2 , may be released as a result of flaring of H 2 S during drilling, completion, or workover operations, the operator shall make SO 2 , portable detection equipment available for checking the SO 2 level in the flare impact area.
Table 32 to § 3176.8 (d)(1)(vi)
(vii) If the flare impact area reaches a sustained ambient threshold level of 2 ppm or greater of SO 2 in air and includes any occupied residence, school, church, park, or place of business, or other area where the public could reasonably be expected to frequent, the Public Protection Plan shall be implemented.
Table 33 to § 3176.8 (d)(1)(vii)
(viii) A remote controlled choke shall be installed for all H 2 S drilling and, where feasible, for completion operations. A remote-controlled valve may be used in lieu of this requirement for completion operations.
Table 34 to § 3176.8 (d)(1)(viii)
(ix) Mud-gas separators and rotating heads shall be installed and operable for all exploratory wells.
Table 35 to § 3176.8 (d)(1)(ix)
(2) Mud program. (i) A pH of 10 or above in a fresh water-base mud system shall be maintained to control corrosion, H 2 S gas returns to surface, and minimize sulfide stress cracking and embrittlement unless other formation conditions or mud types justify to the authorized officer a lesser pH level is necessary.
Table 36 to § 3176.8 (d)(2)(i)
(ii) Drilling mud containing H 2 S gas shall be degassed in accordance with API RP-49, sec. 5.14 (incorporated by reference, see § 3176.11), at an optimum location for the rig configuration. These gases shall be piped into the flare system. (The use of later editions of API RP-49 is deemed to comply with the requirements of this paragraph (d)(2)(ii).)
Table 37 to § 3176.8 (d)(2)(ii)
(iii) Sufficient quantities of mud additives shall be maintained on location to scavenge and/or neutralize H 2 S where formation pressures are unknown.
Table 38 to § 3176.8 (d)(2)(iii)
(3) Metallurgical equipment. (i) All equipment that has the potential to be exposed to H 2 S shall be suitable for H 2 S service. Equipment which shall meet these metallurgical standards include the drill string, casing, wellhead, blowout preventer assembly, casing head and spool, rotating head, kill lines, choke, choke manifold and lines, valves, mud-gas separators, drill-stem test tools, test units, tubing, flanges, and other related equipment.
(ii) To minimize stress corrosion cracking and/or H 2 S embrittlement, the equipment shall be constructed of material whose metallurgical properties are chosen with consideration for both an H 2 S working environment and the anticipated stress. The metallurgical properties of the materials used shall conform to NACE MR 0175-2021 (incorporated by reference, see § 3176.11). (The use of NACE MR 0175-90 through NACE MR 0175-2021 is deemed to comply with the requirements of this paragraph (d)(3)(ii).) These metallurgical properties include the grade of steel, the processing method (rolled, normalized, tempered, and/or quenched), and the resulting strength properties. The working environment considerations include the H 2 S concentration, the well fluid pH, and the wellbore pressures and temperatures. Elastomers, packing, and similar inner parts exposed to H 2 S shall be resistant at the maximum anticipated temperature of exposure. The manufacturer's verification of design for use in an H 2 S environment shall be sufficient verification of suitable service in accordance with this subpart.
Table 39 to § 3176.8 (d)(3)(ii)
(4) Well testing in an H 2 S environment. Testing shall be performed with a minimum number of personnel in the immediate vicinity which are necessary to safely and adequately operate the test equipment. Except with prior approval by the authorized officer, the drill-stem testing of H 2 S zones shall be conducted only during daylight hours and formation fluids shall not be flowed to the surface (closed chamber only).
Table 40 to § 3176.8 (d)(4)
§ 3176.9   Production requirements.
(a) General. (1) All existing production facilities which do not currently meet the requirements and minimum standards set forth in this section shall be brought into conformance within 1 year after January 22, 1991. All existing equipment that is in a safe working condition as of January 22, 1991, is specifically exempt from the metallurgical requirements prescribed in paragraph (c)(7) of this section.
Table 1 to § 3176.9 (a)(1)
(2) Production facilities constructed after January 22, 1991, shall be designed, constructed, and operated to meet the requirements and minimum standards set forth in this section. Any variations from the standards or established time frames shall be approved by the authorized officer in accordance with the provisions of § 3176.10. Except for storage tanks, a determination of the radius of exposure for all production facilities shall be made in the manner prescribed in § 3176.4.
Table 2 to § 3176.9 (a)(2)
(3) At any production facility or storage tank(s) where the sustained ambient H 2 S concentration is in excess of 10 ppm at 50 feet from the production facility or storage tank(s) as measured at ground level under calm (1 mph) conditions, the operator shall collect or reduce vapors from the system and they shall be sold, beneficially used, reinjected, or flared provided terrain and conditions permit.
Table 3 to § 3176.9 (a)(3)
(b) Storage tanks. Storage tanks containing produced fluids and utilized as part of a production operation and operated at or near atmospheric pressure, where the vapor accumulation has an H 2 S concentration in excess of 500 ppm in the tank, shall be subject to the following:
(1) No determination of a radius of exposure need be made for storage tanks.
(2) All stairs/ladders leading to the top of storage tanks shall be chained and/or marked to restrict entry. For any storage, tank(s) which require fencing (see paragraph (b)(6) of this section), a danger sign posted at the gate(s) shall suffice in lieu of this requirement.
Table 4 to § 3176.9 (b)(2)
(3) A danger sign shall be posted on or within 50 feet of the storage tank(s) to alert the public of the potential H 2 S danger. For any storage tank(s) which require fencing (see paragraph (b)(6) of this section), a danger sign posted at the locked gate(s) shall suffice in lieu of this requirement.
Table 5 to § 3176.9 (b)(3)
(4) The sign(s) shall be painted in high-visibility red, black, and white. The sign(s) shall read: “DANGER—POISON GAS—HYDROGEN SULFIDE” or equivalent language if approved by the authorized officer. Where appropriate, bilingual or multilingual warning signs shall be used.
Table 6 to § 3176.9 (b)(4)
(5) At least 1 permanent wind direction indicator shall be installed so that wind direction can be easily determined at or approaching the storage tank(s).
Table 7 to § 3176.9 (b)(5)
(6) A minimum 5-foot chain-link, 5-strand barbed wire, or comparable type fence and gate(s) that restrict(s) public access shall be required when storage tanks are located within 1/4 mile of or contained inside a city or incorporated limits of a town or within 1/4 mile of an occupied residence, school, church, park, playground, school bus stop, place of business, or where the public could reasonably be expected to frequent.
Table 8 to § 3176.9 (b)(6)
(7) Gate(s), as required by paragraph (b)(6) of this section, shall be locked when unattended by the operator.
Table 9 to § 3176.9 (b)(7)
(c) Production facilities. Production facilities containing 100 ppm or more of H 2 S in the gas stream shall be subject to the following:
(1) Danger signs as specified in paragraph (b)(4) of this section shall be posted on or within 50 feet of each production facility to alert the public of the potential H 2 S danger. In the event the storage tanks and production facilities are located at the same site, 1 such danger sign shall suffice. Further, for any facilities which require fencing (paragraph (b)(6) of this section), 1 such danger sign at the gate(s) shall suffice in lieu of this requirement.
Table 10 to § 3176.9 (c)(1)
(2) Danger signs, as specified in paragraph (b)(4) of this section, shall be required for well flowlines and lease gathering lines that carry H 2 S gas. Placement shall be where said lines cross public or lease roads. The signs shall be legible and shall contain sufficient additional information to permit a determination of the owner of the line.
Table 11 to § 3176.9 (c)(2)
(3) Fencing and gate(s), as specified in paragraph (b)(6) of this section, shall be required when production facilities are located within 1/4 mile of or contained inside a city or incorporated limits of a town or within 1/4 mile of an occupied residence, school, church, park, playground, school bus stop, place of business, or any other area where the public could reasonably be expected to frequent. Flowlines are exempted from this additional fencing requirement.
Table 12 to § 3176.9 (c)(3)
(4) Gate(s), as required by paragraph (c)(3) of this section, shall be locked when unattended by the operator.
Table 13 to § 3176.9 (c)(4)
(5) Wind direction indicator(s) as specified in paragraph (b)(5) of this section shall be required. In the event the storage tanks and production facilities are located at the same site, 1 such indicator shall suffice. Flowlines are exempt from this requirement.
Table 14 to § 3176.9 (c)(5)
(6) All wells, unless produced by artificial lift, shall possess a secondary means of immediate well control through the use of appropriate christmas tree and/or downhole completion equipment. Such equipment shall allow downhole accessibility (reentry) under pressure for permanent well control operations. If the applicability criteria stated in § 3176.7(a) are met, a minimum of 2 master valves shall be installed.
Table 15 to § 3176.9 (c)(6)
(7) All equipment shall be chosen with consideration for both the H 2 S working environment and anticipated stresses. NACE MR 0175-2021 (incorporated by reference, see § 3176.11) shall be used for metallic equipment selection and, if applicable, adequate protection by chemical inhibition or other such method that controls or limits the corrosive effects of H 2 S shall be used. (The use of NACE MR 0175-90 through NACE MR 0175-2021 is deemed to comply with the requirements of this paragraph (c)(7).)
Table 16 to § 3176.9 (c)(7)
(8) Where the 100 ppm radius of exposure for H 2 S includes any occupied residence, place of business, school, or other inhabited structure or any area where the public may reasonably be expected to frequent, the operator shall install automatic safety valves or shutdowns at the wellhead, or other appropriate shut-in controls for wells equipped with artificial lift.
Table 17 to § 3176.9 (c)(8)
(9) The automatic safety valves or shutdowns, as required by paragraph (c)(8) of this section, shall be set to activate upon a release of a potentially hazardous volume of H 2 S.
Table 18 to § 3176.9 (c)(9)
(10) If the sustained ambient concentration of H 2 S or SO 2 from a production facility which is venting or flaring reaches a concentration of H 2 S (10 ppm) or SO 2 (2 ppm), respectively, at any of the following locations, the operator shall modify the production facility as approved by the authorized officer. The locations include any occupied residence, school, church, park, playground, school bus stop, place of business, or other areas where the public could reasonably be expected to frequent.
Table 19 to § 3176.9 (c)(10)
(d) Public protection. When conditions as defined in § 3176.7(a) exist, a Public Protection Plan for producing operations shall be submitted to the authorized officer in accordance with § 3176.7(b)(1) which includes the provisions of § 3176.7(b)(2).
Table 20 to § 3176.9 (d)
§ 3176.10   Variances from requirements.
An operator may request the authorized officer to approve a variance from any of the requirements prescribed in §§ 3176.5 through 3176.9. All such requests shall be submitted in writing to the appropriate authorized officer and provide information as to the circumstances which warrant approval of the variance(s) requested and the proposed alternative methods by which the related requirement(a) of minimum standard(s) are to be satisfied. The authorized officer, after considering all relevant factors, may approve the requested variance(s) if it is determined that the proposed alterative(s) meets or exceeds the objectives of the applicable requirement(s) or minimum standard(s).
§ 3176.11   Incorporation by reference.
Certain material is incorporated by reference into this subpart with the approval of the Director of the Federal Register under 5 U.S.C. 552(a) and 1 CFR part 51. All approved incorporation by reference (IBR) material is available for inspection at all Bureau of Land Management offices with jurisdiction over oil and gas activities, and at the National Archives and Records Administration (NARA). Contact the BLM at: Office of Energy, Minerals, and Realty Management, 1849 C Street Northwest, Washington, DC 20240; telephone 202-208-3801; email begruber@blm.gov; website www.blm.gov/programs/energy-and-minerals/oil-and-gas. For information on the availability of this material at NARA, visit www.archives.gov/federal-register/cfr/ibr-locations.html or email fr.inspection@nara.gov. The material also may be obtained from the following sources:
(a) American National Standards Institute (ANSI), 25 West 43rd St., 4th floor, New York, NY 10036; telephone: 212-642-4980; email: info@ansi.org; website: www.ansi.org.
(1) ANSI Standard Z88.2-1992 for Respiratory Protection, Approved August 6, 1992 (“ANSI Z88.2-1992”), IBR approved for § 3176.8.
(2) [Reserved]
If ANSI Z88.2 is not available from document resellers, contact the BLM to obtain a copy.
(b) American Petroleum Institute (API), 200 Massachusetts Avenue NW, Suite 1100, Washington, DC 20001; telephone: 202-682-8000; email: apipubs@api.org; website: www.api.org.
(1) API Recommended Practice 49—Recommended Practice for Drilling and Well Servicing Operations Involving Hydrogen Sulfide; Third Edition, May 2001; Reaffirmed, January 2013 (“API RP 49”), IBR approved for § 3176.8.
(2) [Reserved]
(c) Association for Materials Protection and Performance (AMPP) formerly known as NACE International, 15835 Park Ten Place, Houston, TX 77084; telephone: 1-800-797-6223; website: www.ampp.org.
(1) ANSI/NACE MR0175-2021/ISO 15156-1:2020; Petroleum and natural gas industries—Materials for use in H 2 S-containing environments in oil and gas production; Part 1: General principles for selection of cracking-resistant materials; Fourth Edition, Approved September 21, 2022 (“NACE MR 0175-2021”); IBR approved for §§ 3176.8; 3176.9.
(2) [Reserved]
§ 3177.1   Authority.
This subpart is established pursuant to the authority granted to the Secretary of the Interior by various Federal and Indian mineral leasing statutes and the Federal Oil and Gas Royalty Management Act of 1982. Said authority has been delegated to the Bureau of Land Management and is implemented by the onshore oil and gas operating regulations contained in 43 CFR part 3160. As directed by the Federal Onshore Oil and Gas Leasing Reform Act of 1987, for National Forest lands the Secretary of Agriculture shall regulate all surface-disturbing activities and shall determine reclamation and other actions required in the interest of conservation of surface resources. Specific authority for the provisions contained in this subpart is found at 43 CFR 3162.3 and 3162.5 and 43 CFR part 3160, subpart 3163.
§ 3177.2   Purpose.
This subpart supersedes Notice to Lessees and Operators of Federal and Indian Oil and Gas Leases (NTL-2B), Disposal of Produced Water. The purpose of this subpart is to specify informational and procedural requirements for submittal of an application for the disposal of produced water, and the design, construction, and maintenance requirements for pits as well as the minimum standards necessary to satisfy the requirements and procedures for seeking a variance from the minimum standards. Also set forth in this subpart are certain specific acts of noncompliance, corrective actions required, and the abatement period allowed for correction.
§ 3177.3   Scope.
This subpart is applicable to disposal of produced water from completed wells on Federal and Indian (except Osage) oil and gas leases. It does not apply to approval of disposal facilities on lands other than Federal and Indian lands. Separate approval under this subpart is not required if the method of disposal has been covered under an enhanced recovery project approved by the authorized officer.
§ 3177.4   Definitions.
As used in this subpart, the term:
Authorized officer means any employee of the Bureau of Land Management authorized to perform duties described in 43 CFR parts 3000 and 3100.
Federal lands means all lands and interests in lands owned by the United States which are subject to the mineral leasing laws, including mineral resources or mineral estates reserved to the United States in the conveyance of a surface or nonmineral estate.
Free-board means the vertical distance from the top of the fluid surface to the lowest point on the top of the dike surrounding the pit.
Injection well means a well used for the disposal of produced water or for enhanced recovery operations.
Lease means any contract, profit share arrangement, joint venture, or other agreement issued or approved by the United States under a mineral leasing law that authorized exploration for, extraction of, or removal of oil or gas (see 43 CFR 3160.0-5).
Lessee means a person or entity holding record title in a lease issued by the United States (see 43 CFR 3160.0-5).
Lined pit means an excavated and/or bermed area that is required to be lined with natural or manmade material that will prevent seepage. Such pit shall also include a leak detection system.
Major violation means noncompliance that causes or threatens immediate, substantial, and adverse impacts on public health and safety, the environment, production accountability, or royalty income (see 43 CFR 3160.0-5).
Minor violation means noncompliance that does not rise to the level of a “major violation” (see 43 CFR 3160.0-5).
Natural Pollutant Discharge Elimination System (NPDES) means a program administered by the Environmental Protection Agency or primacy State that requires permits for the discharge of pollutants from any point source into navigable waters of the United States.
Operator means any person or entity, including but not limited to the lessee or operating rights owner, who has stated in writing to the authorized officer that it is responsible under the terms and conditions of the lease for the operations conducted on the leased lands or a portion thereof (see 43 CFR 3610.0-5).
Produced water means water produced in conjunction with oil and gas production.
Toxic constituents means substances in produced water that when found in toxic concentrations specified by Federal or State regulations have harmful effects in plant or animal life. These substances include but are not limited to arsenic (As), barium (Ba), cadmium (Cd), hexavalent chromium (hCr), total chromium (tCr), lead (Pb), mercury (Hg), zinc (Zn), selenium (Se), benzene, toluene, ethylbenzene, and xylenes, as defined in 40 CFR part 261.
Underground Injection Control (UIC) program means a program by administered by the EPA, primacy State, or Indian Tribe under the Safe Drinking Water Act to ensure that subsurface injection does not endanger underground sources of drinking water.
Unlined pit means an excavated and/or bermed area that is not required to be lined, or any pit that is lined but does not contain a leak detection system.
§ 3177.5   Requirements.
(a) General requirements. Operators of onshore Federal and Indian oil and gas leases shall comply with the requirements and standards of this subpart for the protection of surface and subsurface resources. Except as provided under § 3177.8(c), the operator may not dispose of produced water unless and until approval is obtained from the authorized officer. All produced water from Federal/Indian leases must be disposed of by injection into the subsurface, discharging into pits, or other acceptable methods approved by the authorized officer, including surface discharge under NPDES permit. Injection is generally the preferred method of disposal. Operators are encouraged to contact the appropriate authorized officer before filing an application for disposal of produced water so that the operator may be apprised of any existing agreements outlining cooperative procedures between the Bureau of Land Management and either the State/Indian Tribe or the Environmental Protection Agency concerning Underground Injection Control permits for injection wells, and of any potentially significant adverse effects on surface and/or subsurface resources. The approval of the Environmental Protection Agency or a State/Tribe shall not be considered as granting approval to dispose of produced water from leased Federal or Indian lands until and unless BLM approval is obtained. Applications filed pursuant to NTL-2B and still pending approval shall be supplemented or resubmitted if they do not meet the requirements and standards of this subpart. The disposal methods shall be approved in writing by the authorized officer regardless of the physical location of the disposal facility. Existing NTL-2B approvals will remain valid. However, upon written justification, the authorized officer may impose additional conditions or revoke any previously approved disposal permit, if the authorized officer, for example, finds that an existing facility is creating environmental problems, or that an unlined pit should be lined, because the quality of the produced water has changed so that it no longer meets the standards for unlined pits set out in this subpart.
(b) Temporary disposal. Unless prohibited by the authorized officer, produced water from newly completed wells may be temporarily disposed of into reserve pits for a period of up to 90 days, if the use of the pit was approved as a part of an application for permit to drill. Any extension of time beyond this period requires documented approval by the authorized officer.
(c) Approval timeline. (1) Upon receipt of a completed application the authorized officer shall take one of the following actions within 30 days:
(i) Approve the application as submitted or with appropriate modification or conditions;
(ii) Return the application and advise the applicant in writing of the reasons for disapproval; or
(iii) Advise the applicant in writing of the reasons for delay and the excepted final action date.
(2) If the approval for a disposal facility, e.g., commercial pit or class II injection well, is revoked or suspended by the permitting agencies such as the Environmental Protection Agency or the primacy State, the BLM water disposal approval is immediately terminated and the operator is required to propose an alternative disposal method.
§ 3177.6   Application and approval authority.
(a) On-lease disposal. For water produced from a Federal/Indian lease and disposed of on the same Federal/Indian lease, or on other committed Federal/Indian leases if in a unit or communitized area, the approval of the disposal method is usually granted in conjunction with the approval for the disposal facilities. An example would be the approval of a proposal to drill an injection well to be used for the disposal of produced water from a well or wells on the same lease.
(1) Disposal of water in injection wells. When approval is requested for on-lease disposal of produced water into an injection well, the operator shall submit a Sundry Notice, Form 3160-5. Information submitted in support of obtaining the Underground Injection Control permit shall be accepted by the authorized officer in approving the disposal method, provided the information submitted in support of obtaining such a permit satisfies all applicable Bureau of Land Management statutory responsibilities (including but not limited to drilling safety, down hole integrity, and protection of mineral and surface resources) and requirements in this subpart. If the authorized officer has on file a copy of the approval for the receiving facilities, he/she may determine that a reference to that document is sufficient.
(2) Disposal of water in pits. When approval is requested for disposal of produced water in a lined or unlined pit, the operator shall submit a Sundry Notice, Form 3160-5. The operator shall comply with all the applicable Bureau of Land Management requirements and standards for pits established in this subpart. On National Forest lands, where the proposed pit location creates new surface disturbance, the authorized officer shall not approve the proposal without the prior approval of the Forest Service.
(b) Off-lease disposal —(1) On leased or unleased Federal/Indian lands. The purpose of the off-lease disposal approval process is to ensure that the removal of the produced water from a Federal or Indian oil and gas lease is proper and that the water is disposed of in an authorized facility. Therefore, the operator shall submit a Sundry Notice, Form 3160-5, for removal of the water together with a copy of the authorization for the disposal facility. If the authorized officer has a copy of the approval for the receiving facilities on file, he/she may determine that a reference to that document is sufficient. Where an associated right-of-way authorization is required, the information for the right-of-way authorization may be incorporated in the Sundry Notice, and the Bureau of Land Management will process both authorizations simultaneously for Bureau lands.
(i) Disposal of water in injection wells. When approval is requested for removing water that is produced from wells on leased Federal or Indian lands and that is to be injected into a well located on another lease or unleased Federal lands, the operator shall submit to the authorized officer a Sundry Notice, Form 3160-5, along with a copy of the Underground Injection Control permit issued to the operator of the injection well, unless the well is authorized by rule under 40 CFR part 144.
(ii) Disposal of water in pits. When approval is requested for removing water that is produced from wells on leased Federal or Indian lands and is to be disposed of into a lined or unlined pit located on another lease or unleased Federal lands, the operator shall submit to the authorized officer a Sundry Notice, Form 3160-5.
(iii) Right-of-way procedures. The operator of the injection well or pit is required to have an authorization from the Bureau of Land Management for disposing of the water into the pit or well, under Title V of the Federal Land Policy and Management Act (FLPMA) and 43 CFR part 2800, or a similar authorization from the responsible surface management agency. In transporting the produced water from the lease to the pit or injection well, e.g., building a road or laying a pipeline, a right-of-way authorization under Title V of FLPMA and 43 CFR part 2800 from the Bureau of Land Management or a similar permit from the responsible surface management agency also shall be obtained by the operator of the pit or any injection well or other responsible party.
(2) Disposal of water on State and privately owned lands —(i) Disposal of water in injection wells. When approval is requested for removing water that is produced from wells on leased Federal or Indian lands and that is to be injected into a well located on State or privately owned lands, the operator shall submit to the authorized officer, in addition to a Sundry Notice, Form 3160-5, a copy of the Underground Injection Control permit issued for the injection well by Environmental Protection Agency or the State where the State has achieved primacy. Submittal of the Underground Injection Control permit will be accepted by the authorized officer and approval will be granted for the removal of the produced water unless the authorized officer states in writing that such approval will have adverse effects on the Federal/Indian lands or public health and safety.
(ii) Disposal of water in pits. When approval is requested for removing water that is produced from wells on leased Federal and/or Indian lands and is to be disposed of into a pit located on State or privately owned lands, the operator shall submit to the authorized officer, in addition to a Sundry Notice, Form 3160-5, a copy of the permit issued for the pit by the State or any other regulatory agency, if required, for disposal in such pit. Submittal of the permit will be accepted by the authorized officer and approval will be granted for removal of the produced water unless the authorized officer states in writing that such approval will have adverse effects on the Federal/Indian lands or public health and safety. If such a permit is not issued by the State or other regulatory agency, the requested removal of the produced water from leased Federal or Indian lands will be denied.
(iii) Right-of-way procedures. If the water produced from wells on leased Federal and/or Indian lands, and to be disposed of at a location on State or privately owned lands, will be transported over off-lease Federal or Indian lands, the operator of the disposal facility or other responsible party shall have an authorization from the Bureau of Land Management under Title V of FLPMA and 43 CFR part 2800, or a similar authorization from the responsible surface management agency.
§ 3177.7   Informational requirements for injection wells.
For an injection well proposed on Federal or Indian leases, the operator shall obtain an Underground Injection Control (UIC) permit pursuant to 40 CFR parts 144 and 146 from the Environmental Protection Agency or the State/Tribe where the State/Tribe has achieved primacy. The operator shall also comply with the pertinent procedural and informational requirements for Application for Permit to Drill or Sundry Notice as set forth in subpart 3171 of this part. The injection well shall be designed and drilled or conditioned in accordance with the requirements and standards described in subpart 3172 of this part and pertinent NTLs, as well as the UIC permit.
§ 3177.8   Informational requirements for pits.
Operators who request approval for disposal of produced water into a lined or unlined pit shall file an application on a Sundry Notice, Form 3160-5, and identify the operator's field representative by name, address, and telephone number and the source of the produced water. Sources of produced water shall be identified by facility, lease number, well number and name, and legal description of well location. All samples for water analysis shall be taken at the current discharge a point. A reclamation plan detailing the procedures expected to be followed for closure of the pit and the contouring and revegetating of the site shall be submitted prior to pit abandonment. If requested by the authorized officer, a contingency plan to deal with specific anticipated emergency situations shall be submitted as provided for in 43 CFR 3162.5-1(d).
(a) Lined pits. The authorized officer shall not consider for approval an application for disposal into lined pits on Federal/Indian leases unless the operator also provides the following information:
(1) A map and drawings of the site on a suitable scale that show the pit dimension, cross section, side slopes, leak detection system, and location relative to other site facilities;
(2) The daily quantity of water to be disposed of (maximum daily quantity shall be cited if major fluctuations are anticipated) and a water analysis (unless waived by the authorized officer as unnecessary) that includes the concentrations of chlorides, sulfates, pH, total dissolved solids (TDS), and toxic constituents that the authorized officer reasonably believes to be present;
(3) Criteria used to determine the pit size, which includes a minimum of 2 feet of free-board;
(4) The average monthly evaporation and average monthly precipitation for the area;
(5) The method and schedule for periodic disposal of precipitated solids and a copy of the appropriate disposal permit, if any; and
(6) The type, thickness, and life span of material to be used for lining the pit and the method of installation. The manufacturer's guidebook and information for the product shall be included, if available.
(b) Unlined pits. (1) Application for disposal into unlined pits may be considered for approval by the authorized officer where the application of the operator shows that such disposal meets one or more of the following criteria:
(i) The water to be disposed of has an annual average TDS concentration equal to or less than that of the existing water to be protected, provided that the level of any toxic constituents in the produced water does not exceed established State or Federal standards for protection of surface and/or ground water;
(ii) All, or a substantial part, of the produced water is being used for beneficial purposes and meets minimum water quality standards for such uses. For example, uses of produced water for purposes such as irrigation and livestock or wildlife watering shall be considered as beneficial;
(iii)(A) The water to be disposed of will not degrade the quality of surface or subsurface waters in the area;
(B) The surface and subsurface waters contain TDS above 10,000 ppm, or toxic constituents in high concentrations; or
(C) The surface and subsurface waters are of such poor quality or small quantity as to eliminate any practical use thereof; and
(iv) That the volume of water to be disposed of per disposal facility does not exceed an average of 5 barrels per day on a monthly basis.
(2) Operators applying for disposal into an unlined pit shall also submit the following information, as appropriate:
(i) Applications for disposal into unlined pits that meet the criteria in paragraphs (b)(1)(i) through (iv) of this section shall include:
(A) A map and drawings of the site on a suitable scale that show the pit dimension, cross section, side slopes, size, and location relative to other site facilities;
(B) The daily quantity of water to be disposed of and a water analysis that includes total dissolved solids (in ppm), pH, oil and grease content, the concentrations of chlorides and sulfates, and other parameters or constituents toxic to animal or plant life as reasonably prescribed by the authorized officer. The applicant should also indicate any effect or interaction of produced water with any water resources present at or near the surface and other known mineral deposits. For applications submitted under criterion in paragraph (b)(1)(iv) of this section, the water quality analysis is not needed unless requested by the authorized officer;
(C) The average monthly evaporation and the average monthly precipitation for the area. For applications submitted under criterion in paragraph (b)(1)(iv) of this section, average annual data will be acceptable;
(D) The estimated percolation rate based on soil characteristics under and adjacent to the pit. In some cases the authorized officer may require percolation tests using accepted test procedures; and
(E) Estimated depth and areal extent of the shallowest known aquifer with TDS less than 10,000 ppm, and the depth and extent of any known mineral deposits in the area.
(ii) Where beneficial use (criterion in paragraph (b)(1)(ii) of this section) is the basis for the application, the justification submitted shall also contain written confirmation from the user(s).
(iii) If the application is made on the basis that surface and subsurface waters will not be adversely affected by disposal in an unlined pit (paragraph (b)(1)(iii) of this section), the justification shall also include the following additional information:
(A) Map of the site showing the location of surface waters, water wells, and existing water disposal facilities within 1 mile of the proposed disposal facility;
(B) Average concentration of TDS (in ppm) of all surface and subsurface waters within the 1-mile radius that might be affected by the proposed disposal;
(C) Reasonable geologic and hydrologic evidence that shows the proposed disposal method will not adversely affect existing water quality or major uses of such waters, and identifies the presence of any impermeable barrier(s), as necessary; and
(D) A copy of any State order or other authorization granted as a result of a public hearing that is pertinent to the authorized officer's consideration of the application.
(c) Emergency pits. Application for a permanent pit (lined or unlined) to be used for anticipated emergency purposes shall be submitted by the operator on a Sundry Notice, Form 3160-5, for approval by the authorized officer, unless it has been approved in conjunction with a previously approved operational activity. Design criteria for an emergency pit will be established by the authorized officer on a case-by-case basis. Any emergency use of such pits shall be reported in accordance with NTL-3A, and the pit shall be emptied and the liquids disposed of in accordance with applicable State and/or Federal regulations within 48 hours following its use, unless such time is extended by the authorized officer.
§ 3177.9   Design requirements for pits.
(a) Pits shall be designed to meet the following requirements and minimum standards. For unlined pits approved under criterion in § 3177.8(b)(1)(iv), requirements in paragraphs (a)(4) and (5) of this section, do not apply.
(1) As much as practical, the pit shall be located on level ground and away from established drainage patterns, including intermittent/ephemeral drainage ways, and unstable ground or depressions in the area.
(2) The pit shall have adequate storage capacity for safe containment of all produced water, even in those periods when evaporation rates are at a minimum. The design shall provide for a minimum of 2 feet of free-board.
(3) The pit shall be fenced or enclosed to prevent access by livestock, wildlife, and unauthorized personnel. If necessary, the pit shall be equipped to deter entry by birds. Fences shall not be constructed on the levees. Figure 1 in appendix A to this subpart shows an example of an acceptable fence design.
(4) The pit levees are to be constructed so that the inside grade of the levee is no steeper than 1 (vertical):2 (horizonal), and the outside grade no steeper than 1:3.
(5) The top of levees shall be level and at least 18 inches wide.
(6) The pit location shall be reclaimed pursuant to the requirements and standards of the surface management agency. On a spilt estate (private surface, Federal mineral) a surface owner's release statement or form is acceptable.
(b) Lined pits shall be designed to meet following requirement and minimum standards in addition to those specified in paragraph (a) of this section:
(1) The material used in lining pits shall be impervious. It shall be resistant to weather, sunlight, hydrocarbons, aqueous acids, alkalies, salt, fungi, or other substances likely to be contained in the produced water.
(2) If rigid materials are used, leak-proof expansion joints shall be provided, or the material shall be of sufficient thickness and length to withstand expansion without cracking, contraction, and settling movements in the underlying earth. Semi-rigid liners such as compacted bentonite or clay may also be used provided that, considering the thickness of the lining material chosen and its degree of permeability, the liner is impervious for the expected period of use. Figure 2 in appendix A to this subpart shows examples of acceptable standards for concrete, asphalt, and bentonite/clay liners.
(3) If flexible membrane materials are used, they shall have adequate resistance to tears or punctures. Figure 3 in appendix A to this subpart gives an example of acceptable standards for installation of the flexible membrane.
(4) Lined pits shall have an underlying gravel-filled sump and lateral system or other suitable devices for the detection of leaks. Examples of the acceptable design of the leak detection system are shown in Figures 4 and 5 of appendix A to this subpart.
(c) Failure to design the pit to meet the requirements in paragraphs (a) and (b) of this section and minimum standards in this subpart will result in disapproval of the proposal or a requirement that it be modified unless a request for variance is approved by the authorized officer.
§ 3177.10   Construction and maintenance requirements for pits.
Inspections will be conducted according to the following requirements and minimum standards during the construction and operation of the pit. Failure to meet the requirements and standards may result in issuance of an Incident of Noncompliance (INC) for the violation. The gravity of the violation, corrective actions, and the normal abatement period allowed are specified for each of the requirements/standards.
(a) Any disposal method that has not been approved shall be considered an incident of noncompliance and may result in the issuance of a shut-in order, assessments, or penalties pursuant to 43 CFR part 3163 until an acceptable disposal method is provided and approved by the authorized officer.
Table 1 to § 3177.10 (a)
(b) The operator shall notify the authorized officer to inspect the leak detection system at least 2 business days prior to the installation of the pit liner.
Table 2 to § 3177.10 (b)
(c) At least 2 business days prior to its use, the operator shall notify the authorized officer of completion of the pit construction, so that the authorized officer may verify that the pit has been constructed in accordance with the approved plan.
Table 3 to § 3177.10 (c)
(d) Lined pit shall be maintained and operated to prevent unauthorized subsurface discharge of water.
Table 4 to § 3177.10 (d)
(e) The pit shall be maintained as designed to prevent entrance of surface water by providing adequate surface drainage away from the pit.
Table 5 to § 3177.10 (e)
(f) The pit shall be maintained and operated to prevent unauthorized surface discharge of water.
Table 6 to § 3177.10 (f)
(g) The outside walls of the pit levee shall be maintained as designed to minimize erosion.
Table 7 to § 3177.10 (g)
(h) The pit shall be kept reasonably free from surface accumulation of liquid hydrocarbons that would retard evaporation.
Table 8 to § 3177.10 (h)
(i) The operator shall inspect the leak detection system at least once a month or more often if required by the authorized officer in appropriate circumstances. The record of inspection shall describe the result of the inspection by date and shall be kept and made available to the authorized officer upon request.
Table 9 to § 3177.10 (i)
(j) Prior to pit abandonment and reclamation, the operator shall submit a Sundry Notice for approval by the authorized officer, if not previously approved.
Table 10 to § 3177.10 (j)
(k) When change in the quantity and/or quality of the water disposed into an unlined pit causes the pit no longer to meet the unlined pit criteria listed under § 3177.8(b)(1), the operator shall submit a Sundry Notice amending the pit design for approval by the authorized officer.
Table 11 to § 3177.10 (k)
§ 3177.11   Other disposal methods.
(a) The person applying to use the surface discharge disposal method under an NPDES permit shall furnish a copy of the NPDES permit issued by the EPA or the primacy State, a current water quality analysis, and a Sundry Notice, Form 3160-5, describing site facilities ( e.g., retention ponds, skimmer pits and equipment, tanks, and any additional surface disturbance). Operations from the point of origin to the point of discharge are under the jurisdiction of the BLM. Operations from the point of discharge downstream are under the jurisdiction of the EPA or the primacy State.
(b) Use of existing commercial pits designed for containment of produced water or tanks in lieu of pits.
(c) New technology or any other proposal meeting the objective of this subpart that the authorized officer deems acceptable and that meets the requirements of State and Federal laws and regulations.
§ 3177.12   Reporting requirements for disposal facilities.
All unauthorized discharge or spills from disposal facilities on Federal/Indian leases shall be reported to the authorized officer in accordance with the provisions of NTL-3A.
Table 1 to § 3177.12
§ 3177.13   Variances from requirements or minimum standards.
An operator may request that the authorized officer approve a variance from any of the requirements or minimum standards prescribed in §§ 3177.5 through 3177.12. All such requests shall be submitted in writing to the appropriate authorized officer and provide information as to the circumstances that warrant approval of the variance(s) requested and the proposed alternative means by which the requirements or related minimum standard(s) will be satisfied. The authorized officer, after considering all relevant factors, will approve the requested variance(s) if it is determined that the proposed alterative(s) meet or exceed the objectives of the applicable minimum standard(s); or if the authorized officer determines that the exemption of the requirement is justified. Variances granted by BLM under this section shall be limited to proposals and requirements under BLM statutory and/or regulatory authority only, and shall not be construed as granting variances to regulations under EPA, State, or Tribal authority.
§ 3178.1   Purpose.
The purpose of this subpart is to address the circumstances under which oil or gas produced from Federal and Indian leases may be used royalty-free in operations on the lease, unit, or communitized area. This subpart supersedes those portions of Notice to Lessees and Operators of Onshore Federal and Indian Oil and Gas Leases, Royalty or Compensation for Oil or Gas Lost (NTL-4A), pertaining to oil or gas used for beneficial purposes.
§ 3178.2   Scope.
(a) This subpart applies to:
(1) All onshore Federal and Indian (other than Osage Tribe) oil and gas leases, units, and communitized areas, except as otherwise provided in this subpart;
(2) Indian Mineral Development Act (IMDA) oil and gas agreements, unless specifically excluded in the agreement or unless the relevant provisions of this subpart are inconsistent with the agreement;
(3) Leases and other business agreements and contracts for the development of tribal energy resources under a Tribal Energy Resource Agreement entered into with the Secretary, unless specifically excluded in the lease, other business agreement, or Tribal Energy Resource Agreement;
(4) Committed State or private tracts in a federally approved unit or communitization agreement defined by or established under 43 CFR subpart 3105 or 43 CFR part 3180; and
(5) All onshore wells, and production equipment located on a Federal or Indian lease or a federally approved unit or communitized area, and compressors located on a Federal or Indian lease or a federally approved unit or communitized area and which compress production from the same Federal or Indian lease or federally approved unit or communitized area.
(b) For purposes of this subpart, the term “lease” also includes IMDA agreements.
§ 3178.3   Production on which royalty is not due.
(a) To the extent specified in §§ 3178.4 and 3178.5, royalty is not due on:
(1) Oil or gas that is produced from a lease or communitized area and used for operations and production purposes (including placing oil or gas in marketable condition) on the same lease or communitized area without being removed from the lease or communitized area; or
(2) Oil or gas that is produced from a unit PA and used for operations and production purposes (including placing oil or gas in marketable condition) on the unit, for the same unit PA, without being removed from the unit.
(b) For the uses described in § 3178.5, the operator must obtain prior written BLM approval for the volumes used for operational and production purposes to be royalty free.
§ 3178.4   Uses of oil or gas on a lease, unit, or communitized area that do not require prior written BLM approval for royalty-free treatment of volumes used.
(a) Oil or gas produced from a lease, unit, or communitized area may be used royalty-free for operations and production purposes on the lease, unit, or communitized area without prior written BLM approval in the following circumstances:
(1) Use of fuel to generate power or operate combined heat and power;
(2) Use of fuel to power equipment, including artificial lift equipment, equipment used for enhanced recovery, drilling rigs, and completion and workover equipment;
(3) Use of gas to actuate pneumatic controllers or operate pneumatic pumps at production facilities;
(4) Use of fuel to heat, separate, or dehydrate production;
(5) Use of gas as a pilot fuel or as assist gas for a flare, combustor, thermal oxidizer, or other control device;
(6) Use of fuel to compress or treat gas to place it in marketable condition;
(7) Use of oil to clean the well and improve production, e.g., hot oil treatments. The operator must document the removal of the oil from the tank or pipeline under Onshore Oil and Gas Order No. 3 (Site Security), or any successor regulation;
(8) Use of oil as a circulating medium in drilling operations, if the use is part of an approved Drilling Plan under Onshore Oil and Gas Order No. 1;
(9) Injection of gas for the purpose of conserving gas or increasing the recovery of oil or gas, if the BLM has approved the injection under applicable regulations in parts 3100, 3160, or 3180 of this title; and
(10) Injection of gas that is cycled in a contained gas-lift system.
(b) The volume to be treated as royalty free must not exceed the amount of fuel reasonably necessary to perform the operational function, using equipment of appropriate capacity.
§ 3178.5   Uses of oil or gas on a lease, unit, or communitized area that require prior written BLM approval for royalty-free treatment of volumes used.
(a) Oil or gas produced from a lease, unit, or communitized area may also be used royalty-free for the following operations and production purposes on the lease, unit, or communitized area, but prior written BLM approval is required to ensure that production accountability is maintained:
(1) Use of oil or gas that the operator removes from the pipeline at a location downstream of the Facility Measurement Point (FMP);
(2) Use of gas that has been removed from the lease, unit PA, or communitized area for treatment or processing because of particular physical characteristics of the gas that require the gas to be treated or processed prior to use, where the gas is returned to, and used on, the lease, unit PA, or communitized area from which it was produced; and
(3) Any other types of use of produced oil or gas for operations and production purposes, which are not identified in § 3178.4.
(b)(1) The operator must obtain BLM approval to conduct activities under paragraph (a) of this section by submitting a Form 3160-5, Sundry Notices and Reports on Wells (Sundry Notice) containing the information required under § 3178.9. If the BLM disapproves a request for royalty-free treatment for volumes used under this section, the operator must pay royalties on such volumes. If the BLM approves a request for royalty-free treatment for volumes used under this section, such approval will be deemed effective from the date the request was filed.
(2) With respect to uses under paragraph (a)(1) of this section, the operator must measure the volume of oil or gas used in accordance with Onshore Oil and Gas Orders No. 4 (oil) and 5 (gas) as applicable, or other successor regulations.
(3) With respect to removals under paragraph (a)(2) of this section, the operator must measure any gas returned to the lease, unit, or communitized area under such an approval in accordance with Onshore Oil and Gas Order No. 5 or other successor regulations.
§ 3178.6   Uses of oil or gas moved off the lease, unit, or communitized area that do not require prior written approval for royalty-free treatment of volumes used.
Oil or gas used after being moved off the lease, unit, or communitized area may be treated as royalty free without prior written BLM approval only if the use meets the criteria under § 3178.4 and when:
(a) The oil or gas is transported from one area of the lease, unit, or communitized area to another area of the same lease, unit, or communitized area where it is used, and no oil or gas is added to or removed from the pipeline while crossing lands that are not part of the lease, unit, or communitized area; or
(b) A well is directionally drilled, the wellhead is not located on the producing lease, unit, or communitized area, and oil or gas is used on the same well pad for operations and production purposes for that well.
§ 3178.7   Uses of oil or gas moved off the lease, unit, or communitized area that require prior written approval for royalty-free treatment of volumes used.
(a) Except as provided in § 3178.6(b) and paragraph (b) of this section, royalty is owed on all oil or gas used in operations conducted off the lease, unit, or communitized area.
(b) The BLM may grant prior written approval to treat oil or gas used in operations conducted off the lease, unit, or communitized area as royalty free (referred to as off-lease royalty-free use) if the use is among those listed in § 3178.4(a) and § 3178.5(a) and if:
(1) The equipment or facility in which the operation is conducted is located off the lease, unit, or communitized area for engineering, economic, resource protection, or physical accessibility reasons; and
(2) The operations are conducted upstream of the FMP.
(c) The operator must obtain BLM approval under paragraph (b) of this section by submitting a Sundry Notice containing the information required under § 3178.9. If the BLM disapproves a request for royalty-free treatment for volumes used under this section, the operator must pay royalties on such volumes. If the BLM approves a request for royalty-free treatment for volumes used under this section, such approval will be deemed effective from the date the request was filed.
(d) Approval of measurement or commingling off the lease, unit, or communitized area under other regulations does not constitute approval of off-lease royalty-free use. The operator or lessee must expressly request, and submit its justification for, approval of off-lease royalty-free use.
(e) If equipment or a facility located on a particular lease, unit, or communitized area treats oil or gas produced from properties that are not unitized or communitized with the property on which the equipment or facility is located, in addition to treating oil or gas produced from the lease, unit, or communitized area on which the equipment or facility is located, the operator may report as royalty free only that portion of the oil or gas used as fuel that is properly allocable to the share of production contributed by the lease, unit, or communitized area on which the equipment is located, unless otherwise authorized by the BLM under this section.
§ 3178.8   Measurement or estimation of volumes of oil or gas that are used royalty-free.
(a) The operator must measure or estimate the volumes of royalty-free gas used in operations upstream of the FMP.
(b) The operator must measure the volume of gas that is removed from the product stream downstream of the FMP and used royalty-free pursuant to sections 3178.4 through 3178.7.
(c) The operator must measure the volume of oil that is used royalty-free pursuant to sections 3178.4 through 3178.7. The operator must also document removal of such oil from the tank or pipeline.
(d) If the operator removes oil or gas downstream of the FMP and that oil or gas is used royalty-free pursuant to sections 3178.4 through 3178.7, the operator must apply for an FMP under section 3173.12 to measure the oil or gas that is removed for use.
(e) When estimating gas volumes, the operator must use the best available information to make a reasonable estimate.
(f) Each of the volumes required to be measured or estimated, as applicable, under this subpart, must be reported by the operator following applicable ONRR reporting requirements.
§ 3178.9   Requesting approval of royalty-free treatment when approval is required.
To request written approval of royalty-free use when required under § 3178.5 or § 3178.7, the operator must submit a Sundry Notice that includes the following information:
(a) A complete description of the operation to be conducted, including the location of all facilities and equipment involved in the operation and the location of the FMP;
(b) The volume of oil or gas that the operator expects will be used in the operation, and the method of measuring or estimating that volume;
(c) If the volume of gas expected to be used will be estimated, the basis for the estimate ( e.g., equipment manufacturer's published consumption or usage rates); and
(d) The proposed disposition of the oil or gas used ( e.g., whether gas used would be consumed as fuel, vented through use of a gas-activated pneumatic controller, returned to the reservoir, or used in some other way).
§ 3178.10   Facility and equipment ownership.
The operator is not required to own or lease the equipment or facility that uses oil or gas royalty free. The operator is responsible for obtaining all authorizations, measuring production, reporting production, and all other applicable requirements.
§ 3179.1   Purpose.
The purpose of this subpart is to implement and carry out the purposes of statutes relating to prevention of waste from Federal and Indian (other than The Osage Nation) oil and gas leases, protection of worker safety, conservation of surface resources, and management of the public lands for multiple use and sustained yield. This subpart supersedes those portions of Notice to Lessees and Operators of Onshore Federal and Indian Oil and Gas Leases, Royalty or Compensation for Oil and Gas Lost (NTL-4A) pertaining to, among other things, flaring and venting of produced gas, unavoidably and avoidably lost gas, and waste prevention.
§ 3179.2   Scope.
(a) Except as provided in paragraph (b), this subpart applies to:
(1) All onshore Federal and Indian (other than The Osage Nation) oil and gas leases, units, and communitized areas;
(2) Indian Mineral Development Act (IMDA) agreements, unless specifically excluded in the agreement or unless the relevant provisions of this subpart are inconsistent with the agreement;
(3) Leases and other business agreements and contracts for the development of Tribal energy resources under a Tribal Energy Resource Agreement (TERA) entered into with the Secretary, unless specifically excluded in the lease, other business agreement, or TERA;
(4) Wells, equipment, and operations on State or private tracts that are committed to a federally approved unit or communitization agreement defined by or established under 43 CFR subpart 3105 or 43 CFR part 3180.
(b) Sections 3179.50, 3179.90, and 3179.100 through 3179.102 apply only to operations and production equipment located on a Federal or Indian surface estate. They do not apply to operations and production equipment on State or private tracts, even where those tracts are committed to a federally approved unit or communitization agreement.
(c) For purposes of this subpart, the term “lease” also includes IMDA agreements.
§ 3179.10   Definitions and acronyms.
As used in this subpart, the term:
Automatic ignition system means an automatic ignitor and, where necessary to ensure continuous combustion, a continuous pilot flame.
Capture means the physical containment of natural gas for transportation to market or productive use of natural gas and includes reinjection and royalty-free on-site uses pursuant to subpart 3178.
Compressor station means any permanent combination of one or more compressors that move natural gas at increased pressure through gathering or transmission pipelines, or into or out of storage. This includes, but is not limited to, gathering and boosting stations and transmission compressor stations. The combination of one or more compressors located at a well site, or located at an onshore natural gas processing plant, is not a compressor station.
Gas-to-oil ratio (GOR) means the ratio of gas to oil in the production stream expressed in standard cubic feet of gas per barrel of oil at standard conditions.
Gas well means a well for which the energy equivalent of the gas produced, including its entrained liquefiable hydrocarbons, exceeds the energy equivalent of the oil produced. Unless more specific British thermal unit (Btu) values are available, a well with a gas-to-oil ratio greater than 6,000 standard cubic feet (scf) of gas per barrel of oil is a gas well.
High-pressure flare means an open-air flare stack or flare pit designed for the combustion of natural gas that would normally go to sales.
Leak means a release of natural gas from a component that is not associated with normal operation of the component, when such release is:
(1) A hydrocarbon emission detected by use of an optical-gas-imaging instrument;
(2) At least 500 ppm of hydrocarbon detected using a portable analyzer or other instrument that can measure the quantity of the release; or
(3) A hydrocarbon emission detected via audio, visual, and olfactory means or visible bubbles detected using soap solution. Releases due to normal operation of equipment intended to vent as part of normal operations, such as gas-driven pneumatic controllers and safety-release devices, are not leaks unless the releases exceed the quantities and frequencies expected during normal operations. Releases due to operator errors or equipment malfunctions or from control equipment at levels that exceed applicable regulatory requirements, such as releases from an oil storage tank hatch left open, or an improperly sized combustor, are leaks.
Liquids unloading means the removal of an accumulation of liquid hydrocarbons or water from the wellbore of a completed gas well.
Lost oil or lost gas means produced oil or gas that escapes containment, either intentionally or unintentionally, or is flared before being removed from the lease, unit, or communitized area, and cannot be recovered.
Low-pressure flare means any flare that does not meet the definition of high-pressure flare.
Pneumatic controller means an automated instrument used for maintaining a process condition, such as liquid level, pressure, delta-pressure, or temperature.
§ 3179.11   Severability.
If a court holds any provisions of the regulations in this subpart or their applicability to any person or circumstances invalid, the remainder of this subpart and its applicability to other people or circumstances will not be affected.
§ 3179.30   Incorporation by Reference (IBR).
Certain material is incorporated by reference into this subpart with the approval of the Director of the Federal Register under 5 U.S.C. 552(a) and 1 CFR part 51. To enforce any edition other than that specified in this section, the BLM must publish a rule in the Federal Register, and the material must be reasonably available to the public. All approved incorporation by reference (IBR) material is available for inspection at the Bureau of Land Management (BLM) and at the National Archives and Records Administration (NARA). Contact Yvette M. Fields with the BLM at: Division of Fluid Minerals, 1849 C Street NW, Washington, DC 20240, telephone 240-712-8358; email yfields@blm.gov; https://www.blm.gov/programs/energy-and-minerals/oil-and-gas. The approved material is also available for inspection at all BLM offices with jurisdiction over oil and gas activities. For information on inspecting this material at NARA, visit www.archives.gov/federal-register/cfr/ibr-locations.html or email fr.inspection@nara.gov. The material may be obtained from the following source:
(a) American Petroleum Institute (API), 200 Massachusetts Ave. NW, Suite 1100, Washington, DC 20001; telephone 202-682-8000. API offers free, read-only access to some of the material at http://publications.api.org.
(1) API Manual of Petroleum Measurement Standards Chapter 22.3, Testing Protocol for Flare Gas Metering; First Edition, August 2015 (“API 22.3”), IBR approved for § 3179.71(c).
(2) [Reserved]
(b) [Reserved]
§ 3179.40   Reasonable precautions to prevent waste.
(a) Operators must use all reasonable precautions to prevent the waste of oil or gas developed from the lease.
(b) The Authorized Officer may specify reasonable measures to prevent waste as conditions of approval of an Application for Permit to Drill (APD).
(c) After an APD is approved, the Authorized Officer may order an operator to implement, within a reasonable time, additional reasonable measures to prevent waste at ongoing exploration and production operations.
(d) Reasonable measures to prevent waste may reflect factors including, but not limited to, relevant advances in technology and changes in industry practice.
§ 3179.41   Determining when the loss of oil or gas is avoidable or unavoidable.
For purposes of this subpart:
(a) Lost oil is “unavoidably lost” if the operator has taken reasonable steps to avoid waste, and the operator has complied fully with applicable laws, lease terms, regulations, provisions of a previously approved operating plan, and other written orders of the BLM.
(b) Lost gas is “unavoidably lost” if the operator has taken reasonable steps to avoid waste, the operator has complied fully with applicable laws, lease terms, regulations, provisions of a previously approved operating plan, and other written orders of the BLM; and the gas is lost from the following operations or sources:
(1) Well drilling, subject to the limitations in § 3179.80;
(2) Well completion and recompletion flaring allowances in § 3179.81;
(3) Subsequent well tests, subject to the limitations in § 3179.82;
(4) Exploratory coalbed methane well dewatering;
(5) Emergency situations, subject to the limitations in § 3179.83;
(6) Normal operating losses from a natural-gas-activated pneumatic controller or pump;
(7) Normal operating losses from an oil storage tank or other low-pressure production vessel that is in compliance with §§ 3179.90 and 3174.5(b);
(8) Well venting in the course of downhole well maintenance and/or liquids unloading performed in compliance with § 3179.91;
(9) Leaks, when the operator has complied with the LDAR requirements in §§ 3179.100 and 3179.101;
(10) Facility and pipeline maintenance, such as when an operator must blow-down and depressurize equipment to perform maintenance or repairs;
(11) Pipeline capacity constraints, midstream processing failures, or other similar events that prevent oil-well gas from being transported through the connected pipeline, subject to the limitations in the WMP or self-certification for Applications for Permit to Drill approved after June 10, 2024 or § 3179.70, as applicable;
(12) Flaring of gas from which at least 50 percent of natural gas liquids have been removed on-lease and captured for market, if the operator has notified the BLM through a Sundry Notices and Report on Wells, Form 3160-5 (Sundry Notice) that the operator is conducting such capture and the inlet of the equipment used to remove the natural gas liquids will be a Facility Measurement Point (FMP); or
(13) Flaring of gas from a well that is not connected to a gas pipeline, to the extent that such flaring was authorized by the BLM in the approval of the APD.
(c) Lost oil or gas that is not “unavoidably lost” as defined in paragraphs (a) and (b) of this section is “avoidably lost.”
§ 3179.42   When lost production is subject to royalty.
(a) Royalty is due on all avoidably lost oil or gas.
(b) Royalty is not due on any unavoidably lost oil or gas.
§ 3179.43   Data submission and notification requirements.
(a) Table 1 is a summary of the Sundry Notice requirements in this subpart.
Table 1 to Paragraph (a) —Notification Via Sundry Notice Requirements
(b) Table 2 summarizes the locations in this subpart that require an operator to provide information to the authorized officer upon request.
Table 2 to Paragraph (b) —Information Required at the Request of the AO
(c) Table 3 summarizes the initial LDAR program submission and subsequent annual reporting.
Table 3 to Paragraph ( c )—LDAR Program
§ 3179.50   Safety.
(a) The operator must flare, rather than vent, any gas that is not captured, except when:
(1) Flaring the gas is technically infeasible, such as when volumes are too small to flare;
(2) Under emergency conditions, the loss of gas is uncontrollable, or venting is necessary for safety;
(3) The gas is vented through normal operation of a natural-gas-activated pneumatic controller or pump;
(4) The gas is vented from an oil storage tank;
(5) The gas is vented during downhole well maintenance or liquids unloading activities performed in compliance with § 3179.91;
(6) The gas is vented through a leak;
(7) Venting is necessary to allow non-routine facility and pipeline maintenance, such as when an operator must, upon occasion, blow-down and depressurize equipment to perform maintenance or repairs; or
(8) A release of gas is necessary and flaring is prohibited by Federal, State, local, or Tribal law or regulation, or enforceable permit term.
(b) All flares or combustion devices must be equipped with an automatic ignition system or an on-demand ignition system. Upon discovery of a flare that is venting instead of combusting gas, the BLM may subject the operator to an immediate assessment of $1,000 per violation.
(c) The flare must be placed a sufficient distance from the tanks' containment area and any other significant structures or objects so that the flare does not create a safety hazard. The prevailing wind direction must be taken into consideration when locating the flare.
§ 3179.60   Gas-well gas.
Gas-well gas may not be flared or vented, except where it is unavoidably lost pursuant to § 3179.41(b).
§ 3179.70   Oil-well gas.
(a) Where oil-well gas must be flared due to pipeline capacity constraints, midstream processing failures, or other similar events that prevent produced gas from being transported through the connected pipeline, the oil-well gas is “unavoidably lost” for the purposes of 43 CFR 3162.3-1(j), 43 CFR 3179.41(b)(11), and 3179.42, subject to the following limits:
(1) Flaring of 0.08 Mcf per barrel of oil produced per month between July 1, 2024 and July 1, 2025.
(2) The flaring limit of 0.07 Mcf per barrel of oil produced per month will begin on July 1, 2025.
(3) The flaring limit of 0.06 Mcf per barrel of oil produced per month will begin on July 1, 2026.
(4) The flaring limit of 0.05 Mcf per barrel of oil produced per month will begin on July 1, 2027, and remain at this level.
(b) Where substantial volumes of oil-well gas are flared the BLM may order the operator to curtail or shut-in production as necessary to avoid the undue waste of Federal or Indian gas. The BLM will not issue a shut-in or curtailment order under this paragraph unless the operator has reported flaring in excess of 1 Mcf per barrel of oil produced per month for 3 consecutive months and the BLM confirms that flaring is ongoing.
(c) If a BLM order under paragraph (b) of this section would adversely affect production of oil or gas from non-Federal and non-Indian mineral interests ( e.g., production allocated to a mix of Federal, State, Indian, and private leases under a unit agreement), the BLM may issue such an order only to the extent that the BLM is authorized to regulate the rate of production under the governing unit or communitization agreement. In the absence of such authorization, the BLM will contact the State regulatory authority having jurisdiction over the oil and gas production from the non-Federal and non-Indian interests and request that that entity take appropriate action to limit the waste of gas.
§ 3179.71   Measurement of flared oil-well gas volume.
(a) The operator may commingle flared gas from more than one lease, unit PA, or CA to a common high-pressure flare without BLM approval, subject to the allocation requirement in paragraph (h). The site facility diagram required under § 3173.11 must indicate that the high-pressure flare is a common, commingled flare and list the leases, unit PAs, or CAs contributing gas to the common flare.
(b) The operator must measure flared gas for high-pressure flares for volumes greater than or equal to 1,050 Mcf per month over the averaging period. For high-pressure flares measuring less than 1,050 Mcf per month over the averaging period, operators may estimate the volume flared, as described in paragraph (g) of this section.
(c) High-pressure flares requiring measurement must use either orifice plates and orifice meter tubes, or ultrasonic meters. High-pressure flare measurement systems must meet the following requirements:
(1) Orifice metering systems must comply with the low-volume measurement requirements in § 3175.80, low-volume electronic gas measurement requirements in § 3175.100, and the low-volume gas sampling and analysis requirements in § 3175.110 with the gas sampling location requirements provided in paragraph (d) or (e) of this section.
(2) Ultrasonic metering systems must comply with the following requirements:
(i) Each ultrasonic meter make and model must be tested for flare use. Flare gas meter testing must be conducted and reported pursuant to API 22.3 (incorporated by reference, see § 3179.30) and results must be made available to the AO upon request.
(ii) Ultrasonic meters must be installed and operated for flare use according to the manufacturer's specifications and those specifications must be provided to the AO upon request.
(iii) Ultrasonic metering systems must comply with the low-volume electronic gas measurement requirements in § 3175.100, and the low-volume gas sampling analysis requirements in § 3175.110, except for the gas sampling requirements in paragraph (d) or (e) of this section.
(3) Operators must evaluate the production facility to determine which type of flare measurement is safe for the facility.
(d) The gas sample must be taken from one of the following locations when the high-pressure flare is measuring a single lease, unit PA, or CA:
(1) At the flare meter;
(2) At the gas FMP, if there is a gas FMP at the well site and the gas composition is the same as that of the flare-meter gas; or
(3) At another location approved by the AO with a Sundry Notice submission.
(e) The gas sample must be taken from one of the following locations for a common high-pressure flare that measures more than one lease, unit PA, or CA;
(1) At the flare meter; or
(2) At another location approved by the AO with a Sundry Notice submission.
(f) Appropriate meters must be installed at all high-pressure flares pursuant to paragraph (c) of this section, and gas sampling must be taken from the appropriate location pursuant to paragraph (d) or (e) of this section according to the following phase-in timeline:
Table 1 to Paragraph ( f )—Deadline for Compliance With High-Pressure Flare Measurement, and Gas Sampling Location
(g) For high-pressure flares with volumes less than 1,050 Mcf per month, the flared volume may be estimated, or measured. Estimated flared gas volumes must be based on production reported on the ONRR OGORs over the previous 6 months and calculated as follows:
(h) If a flare is combusting gas that is combined across multiple leases, unit PAs, or CAs, the operator may measure the gas at a single point at the flare and allocate flared volumes based on the oil production while flaring from each lease, unit PA, or CA as follows:
(i) Measurement points for flared volumes are not FMPs for the purposes of subpart 3175.
§ 3179.72   Required reporting and recordkeeping of vented and flared gas volumes.
(a) The operator must report all flared volumes, both avoidable and unavoidable losses, using all applicable ONRR reporting requirements.
(b) The operator must report the flared gas quality in Btu on the OGOR based on the gas analysis required in § 3179.71(d) or (e). The operator must report the same Btu content from a common flare on the OGOR for all the leases, unit PAs, or CAs contributing gas to the flare based on the gas sample analysis.
(c) Starting on September 10, 2024,operators must maintain the following records and make them available to the AO upon request:
(1) Date and time when oil or gas-well flaring begins and ends, the reason for flaring and whether the well, lease, unit PA, or CA was shut-in or returned to sales when the flaring stopped;
(2) Date and time when an emergency begins and ends, the reason for the emergency, whether the gas was vented or flared, and whether the well, lease, unit PA, or CA was shut-in or returned to sales when the emergency ended;
(3) Date and time when manual downhole liquids unloading operation or well purging begins and ends, and whether the well was shut-in or returned to sales at the end of the well maintenance.
§ 3179.73   Prior determinations regarding royalty-free flaring.
(a) Approvals to flare royalty free, which are in effect as of the effective date of this rule, will continue in effect until November 1, 2024. After that date, the royalty-bearing status of all flaring will be determined according to the provisions of this subpart.
(b) The provisions of this subpart do not affect any determination made by the BLM before or after June 10, 2024, with respect to the royalty-bearing status of flaring that occurred prior to June 10, 2024.
§ 3179.80   Loss of well control while drilling.
If, during drilling, gas is lost as a result of loss of well control, the operator must notify the BLM within 24 hours of the start of the loss of the well control event and submit to the BLM a Sundry Notice within 15 days following the conclusion of the event describing the loss of well control. The BLM will determine whether the loss of well control was due to operator negligence. Oil or gas lost as a result of loss of well control is avoidably lost if the BLM determines that the loss of well control was due to operator negligence. The BLM will notify the operator in writing when it determines whether oil or gas was lost due to operator negligence, and whether such loss will qualify as an avoidable loss.
§ 3179.81   Well completion or recompletion flaring allowance.
(a) Gas flared following well completion or recompletion is royalty-free under §§ 3179.41(b)(2) and 3179.42(b) until one of the following occurs:
(1) Thirty days have passed since the beginning of the flowback following completion or recompletion, except as provided in paragraphs (b) and (d) of this section;
(2) The operator has flared 20,000 Mcf of gas; or
(3) Flowback has been routed to the production separator.
(b) The BLM may extend the period specified in paragraph (a)(1) of this section, not to exceed an additional 60 days, based on flowback delays caused by well or equipment problems.
(c) The BLM may increase the limit specified in paragraph (a)(2) of this section by up to an additional 30,000 Mcf of gas for exploratory oil wells in remote locations where additional flaring may be needed in advance of construction of pipeline infrastructure.
(d) During the dewatering and initial evaluation of an exploratory coalbed methane well, the 30-day period specified in paragraph (a)(1) of this section is extended to 90 days. The BLM may approve up to two extensions of this evaluation period, not to exceed 90 days per each approval.
(e) The operator must submit its request for an extension under paragraphs (b), (c), or (d) of this section using a Sundry Notice.
§ 3179.82   Subsequent well tests for an existing completion.
During well tests subsequent to the initial completion or recompletion, the operator may flare gas royalty free under § 3179.41(b)(3) for no more than 24 hours, unless the BLM approves or requires a longer period. The operator must submit any such request using a Sundry Notice.
§ 3179.83   Emergencies.
(a) An operator may flare or, if flaring is not feasible due to the emergency situation, vent gas royalty-free under § 3179.41(b)(5) for no longer than 48 hours during an emergency situation. For purposes of this subpart, an “emergency situation” is a temporary, infrequent, and unavoidable situation in which the loss of gas is necessary to avoid a danger to human health, safety, or the environment.
(b) The following examples do not constitute emergency situations for the purposes of royalty assessment:
(1) Recurring failures of a single piece of equipment;
(2) The operator's failure to install appropriate equipment of a sufficient capacity to accommodate the production conditions;
(3) Failure to limit production when the production rate exceeds the capacity of the related equipment, pipeline, or gas plant, or exceeds sales contract volumes of oil or gas;
(4) Scheduled maintenance; or
(5) A situation caused by operator negligence.
(c) Within 45 days of the start of the emergency, the operator must estimate and report to the AO by a Sundry Notice the volumes flared or vented beyond the timeframe specified in paragraph (a) of this section, and details describing the emergency event, measures taken to prevent the emergency event, and actions taken to control the emergency event so that the BLM is able to determine if the loss of oil or gas is an unavoidable loss pursuant to § 3179.41.
§ 3179.90   Oil storage tank vapors.
(a) The hatch on an oil storage tank may be open only to the extent necessary to conduct production and measurement operations. All oil storage tanks, hatches, connections, and other access points must be vapor tight ( i.e. , capable of holding pressure differential at the installed pressure-relieving or vapor-recovery device's settings). Upon discovery of an oil storage tank hatch that has been left open or unlatched, and unattended, the BLM will impose an immediate assessment of $1,000 on the operator.
(b) Where practical and safe, gas released from an oil storage tank must be flared rather than vented. An operator may commingle vapors from multiple storage tanks to a single flare without prior approval from the BLM.
§ 3179.91   Downhole well maintenance and liquids unloading.
(a) Gas vented or flared during downhole well maintenance and well purging is royalty free for a period not to exceed 24 hours per event, provided that the requirements of paragraphs (b) through (d) of this section are met. Gas vented or flared from a plunger lift system and/or an automated well control system is royalty free, provided the requirements of paragraphs (b) and (c) of this section are met.
(b) The operator must minimize the loss of gas associated with downhole well maintenance and liquids unloading, consistent with safe operations.
(c) For wells equipped with a plunger lift system and/or an automated well control system, minimizing gas loss under paragraph (b) of this section includes optimizing the operation of the system to minimize gas losses to the extent possible, consistent with removing liquids that would inhibit proper function of the well.
(d) For any liquids unloading by manual well purging, the operator must ensure that the person conducting the well purging remains present on-site throughout the unloading to end it as soon as practical, thereby minimizing any venting to the atmosphere.
(e) For purposes of this section, “well purging” means blowing accumulated liquids out of a wellbore by reservoir pressure, whether manually or by an automatic control system that relies on real-time pressure or flow, timers, or other well data, where the gas is vented to the atmosphere. Well purging does not apply to wells equipped with a plunger lift system.
§ 3179.92   Size of production equipment.
Production and processing equipment must be of sufficient size to accommodate the volumes of production expected to occur at the lease site.
§ 3179.100   Leak detection and repair program.
(a) Pursuant to paragraph (b) of this section, the operator must maintain a BLM administrative statewide LDAR program designed to prevent the waste of Federal or Indian gas.
(b) Operators must submit a statewide LDAR program to the BLM state office with jurisdiction over the production for review. The LDAR program must cover operations and production equipment located on a Federal or Indian oil and gas lease and not operations and production equipment located on State or private tracts, even though those tracts are committed to a federally approved unit PA or CA. When there is a change of operator, the new operator must update the LDAR program on the annual update and revision timeline. Operators must submit the LDAR program in writing for review until such time as the BLM's electronic filing system is capable of receiving LDAR program submissions. At minimum, the LDAR program must contain the following information, as applicable:
(1) Identification of the leases, unit PAs, CAs by geographic State for all States within BLM's administrative State boundaries to which the LDAR program applies; and
(2) Identification of the method and frequency of leak detection inspection used at the lease, unit PA, or CA. Acceptable methods, as well as other methods approved by the BLM, and frequency include the following:
(i) Well pads with only wellheads and no production equipment or storage must include quarterly Audio-Visual-Olfactory (AVO) inspections for leak detection;
(ii) Well pads with any production and processing equipment and oil storage must include AVO inspections every other month and quarterly optical gas imaging for leak detection; and
(iii) Other leak detection inspection methods and frequency acceptable to the BLM ( e.g., continuous monitoring).
(3) Identification of the operator's recordkeeping process for leak detection and repair pursuant to § 3179.102.
(c) The BLM will review the operator's LDAR program and notify the operator if the BLM deems the program to be inadequate. The notification will explain the basis for the BLM's determination, identify the plan's inadequacies, describe any additional measures that could address the inadequacies, and provide a reasonable time frame in which the operator must submit a revised LDAR program to the BLM for review.
(d) For leases in effect on June 10, 2024, the operator must submit a statewide LDAR program to the state office no later than December 10, 2025.
(e) Operators must review and update submitted LDAR programs on an annual basis in the month in which the operator submitted the first LDAR program to ensure the identified leases, unit PAs, and CAs, leak detection methods, and frequency of inspections are current. If the operator's LDAR program requires no changes, then the operator must notify the BLM state office that the LDAR program submitted and reviewed by the BLM remains in effect. Any updates to the LDAR program must be submitted in writing to the BLM state office for review until such time as the BLM's electronic system is capable of receiving the annual LDAR updates.
§ 3179.101   Repairing leaks.
(a) The operator must repair any leak as soon as practicable, and in no event later than 30 calendar days after discovery, unless good cause exists to delay the repair for a longer period. Good cause for delay of repair exists if the repair (including replacement) is technically infeasible (including unavailability of parts that have been ordered), would require a pipeline blowdown, a compressor station shutdown, or a well shut-in, or would be unsafe to conduct during operation of the unit.
(b) If there is good cause for delaying the repair beyond 30 calendar days, the operator must notify the BLM of the cause by Sundry Notice and must complete the repair at the earliest opportunity, such as during the next compressor station shutdown, well shut-in, or pipeline blowdown. In no case will the BLM approve a delay of more than 2 years.
(c) Not later than 30 calendar days after completion of a repair, the operator must verify the effectiveness of the repair by conducting a follow-up inspection using an appropriate instrument or a soap bubble test under Section 8.3.3 of EPA Method 21—Determination of Volatile Organic Compound Leaks (40 CFR Appendix A-7 to part 60).
(d) If the repair is not effective, the operator must complete additional repairs within 15 calendar days and conduct follow-up inspections and repairs until the leak is repaired.
§ 3179.102   Required recordkeeping for leak detection and repair.
(a) The operator must maintain the following records for the period required under 43 CFR 3162.4-1(d) and make them available to the AO upon request:
(1) For each inspection required under § 3179.100 of this subpart, documentation of:
(i) The date of the inspection; and
(ii) The site where the inspection was conducted;
(2) The monitoring method(s) used to determine the presence of leaks;
(3) A list of leak components on which leaks were found;
(4) The date each leak was repaired; and
(5) The date and result of the follow-up inspection(s) required under § 3179.101(c).
(b) With the annual review and update of the LDAR program under § 3179.100(e) the operator must provide to the BLM state office an annual summary report on the previous year's inspection activities that includes:
(1) The number of sites inspected;
(2) The total number of leaks identified, categorized by the type of component;
(3) The total number of leaks that were not repaired from the previous LDAR program year due to good cause and an estimated date of repair for each leak.
(c) AVO checks are not required to be documented unless they find a leak requiring repair.
§ 3179.200   Immediate assessments
Certain instances of noncompliance warrant the imposition of immediate assessments upon the violation, as prescribed in the following table. Imposition of any of these assessments does not preclude other appropriate enforcement actions under other applicable regulations.
Table 1 to § 3179.200—Violations Subject to Immediate Assessment
This action by the Principal Deputy Assistant Secretary is taken pursuant to an existing delegation of authority.