The authorities for promulgating the regulations in this part are the Mineral Leasing Act, 30 U.S.C. 181 et seq.; the Mineral Leasing Act for Acquired Lands, 30 U.S.C. 351 et seq.; the Federal Oil and Gas Royalty Management Act, 30 U.S.C. 1701 et seq.; the Indian Mineral Leasing Act, 25 U.S.C. 396a et seq.; the Act of March 3, 1909, 25 U.S.C. 396; the Indian Mineral Development Act, 25 U.S.C. 2101 et seq.; and the Federal Land Policy and Management Act, 43 U.S.C. 1701 et seq. Each of these statutes gives the Secretary the authority to promulgate necessary and appropriate rules and regulations governing Federal and Indian (except Osage Tribe) oil and gas leases. See 30 U.S.C. 189; 30 U.S.C. 359; 25 U.S.C. 396d; 25 U.S.C. 396; 25 U.S.C. 2107; and 43 U.S.C. 1740. Under Secretarial Order Number 3087, dated December 3, 1982, as amended on February 7, 1983 (48 FR 8983), and the Departmental Manual (235 DM 1.1), the Secretary has delegated regulatory authority over onshore oil and gas development on Federal and Indian (except Osage Tribe) lands to the BLM. For Indian leases, the delegation of authority to the BLM is reflected in 25 CFR parts 211, 212, 213, 225, and 227. In addition, as authorized by 43 U.S.C. 1731(a), the Secretary has delegated to the BLM regulatory responsibility for oil and gas operations on Indian lands. 235 DM 1.1.K.
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ONSHORE OIL AND GAS PRODUCTION
(a) The Secretaries of the Interior and Agriculture have authority under various Federal and Indian mineral leasing laws, as defined in 30 U.S.C. 1702, to manage oil and gas operations. The Secretary of the Interior has delegated this authority to the Bureau of Land Management (BLM), which has issued onshore oil and gas operating regulations codified at 43 CFR part 3160. For leases on Indian lands, the delegation to the BLM appears at 25 CFR parts 211, 212, 213, 225, and 227.
(b) The Secretary of Agriculture has authority under the Federal Onshore Oil and Gas Leasing Reform Act of 1987 (Pub. L. 100-203) (Reform Act) to regulate surface disturbing activities conducted pursuant to a Federal oil and gas lease on National Forest Service (NFS) lands. This authority has been delegated to the Forest Service (FS). Its regulatory authority is at 36 CFR chapter II, including, but not limited to, part 228, subpart E, part 251, subpart B, and part 261. The FS is responsible only for approving and regulating surface disturbing activities on NFS lands and appeals related to FS decisions or approvals.
(a) This subpart is established pursuant to the authority granted to the Secretary of the Interior pursuant to various Federal and Indian mineral leasing statutes and the Federal Oil and Gas Royalty Management Act of 1982. This 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.
(b) Specific authority for the provisions contained in this subpart is found at: 43 CFR 3162.3-1, 3162.3-4, 3162.4-1, 3162.4-3, 3162.5-1, 3162.5-2 (see paragraph (a)), and 3162.5-3; and 43 CFR part 3160, subpart 3163.
(a) As used in this subpart, the term:
Access means the ability to:
(i) Add liquids to or remove liquids from any tank or piping system, through a valve or combination of valves or by moving liquids from one tank to another tank; or
(ii) Enter any component in a measuring system affecting the accuracy of the measurement of the quality or quantity of the liquid being measured.
Appropriate valves means those valves that must be sealed during the production or sales phase ( e.g., fill lines, equalizer, overflow lines, sales lines, circulating lines, or drain lines).
Authorized representative (AR) has the same meaning as defined in 43 CFR 3160.0-5.
Business day means any day Monday through Friday, excluding Federal holidays.
Commingling and allocation approval (CAA) means a formal allocation agreement to combine production from two or more sources (leases, unit PAs, CAs, or non-Federal or non-Indian properties) before that product reaches an FMP.
Economically marginal property means a lease, unit PA, or CA that does not generate sufficient revenue above operating costs, such that a prudent operator would opt to plug a well or shut-in the lease, unit PA, or CA instead of making the investments needed to achieve non-commingled measurement of production from that lease, unit PA, or CA. A lease, unit PA, or CA may be regarded as economically marginal if the operator demonstrates that the expected revenue (net any associated operating costs) generated from crude oil or natural gas production volumes on that property is not sufficient to cover the nominal cost of the capital expenditures required to achieve measurement of non-commingled production of oil or gas from that property over a payout period of 18 months. A lease, unit PA, or CA can also be considered economically marginal if the operator demonstrates that its royalty net present value (RNPV), or the discounted value of the Federal or Indian royalties collected on revenue earned from crude oil or natural gas production on the lease, unit PA, or CA, over the expected life of the equipment that would need to be installed to achieve non-commingled measurement volumes, is less than the capital cost of purchasing and installing this equipment. Both the payout period and the RNPV are determined separately for each lease, unit PA, or CA oil or gas FMP. Additionally, oil FMPs are evaluated using estimated revenue (net of taxes and operating costs) from crude oil production, as defined in this section, while gas FMPs are evaluated using estimated revenue (net of taxes and operating costs) from natural gas production, as defined in this section.
Effectively sealed means the placement of a seal in such a manner that the sealed component cannot be accessed, moved, or altered without breaking the seal.
Free water means the measured volume of water that is present in a container and that is not in suspension in the contained liquid at observed temperature.
Land description means a location surveyed in accordance with the U.S. Department of the Interior's Manual of Surveying Instructions (2009), that includes the quarter-quarter section, section, township, range, and principal meridian, or other authorized survey designation acceptable to the AO, such as metes-and-bounds, or latitude and longitude.
Maximum ultimate economic recovery has the same meaning as defined in 43 CFR 3160.0-5.
Mishandling means failing to measure or account for removal of production from a facility.
Payout period means the time required, in months, for the cost of an investment in an oil or gas FMP for a specific lease, unit PA, or CA to be covered by the nominal revenue earned from crude oil production, for an oil FMP, or natural gas production, for a gas FMP, minus taxes, royalties, and any operating and variable costs. The payout period is determined separately for each oil or gas FMP for a given lease, unit PA, or CA.
Permanent measurement facility means all equipment constructed or installed and used on-site for 6 months or longer, for the purpose of determining the quantity, quality, or storage of production, and which meets the definition of FMP under § 3170.3.
Piping means a tubular system ( e.g., metallic, plastic, fiberglass, or rubber) used to move fluids (liquids and gases).
Production phase means that event during which oil is delivered directly to or through production equipment to the storage facilities and includes all operations at the facility other than those defined by the sales phase.
Royalty Net Present Value (RNPV) means the net present value of all Federal or Indian royalties paid on revenue earned from crude oil production or natural gas production from an oil or gas FMP for a given lease, unit PA, or CA over the expected life of metering equipment that must be installed for that lease, unit PA, or CA to achieve non-commingled measurement.
Sales phase means that event during which oil is removed from storage facilities for sale at an FMP.
Seal means a uniquely numbered device that completely secures either a valve or those components of a measuring system that affect the quality or quantity of the oil being measured.
(b) As used in this subpart, the following additional acronyms apply:
BIA means the Bureau of Indian Affairs.
BMP means Best Management Practice.
(a) As used in this subpart, the term:
Barrel (bbl) means 42 standard United States gallons.
Base pressure means 14.696 pounds per square inch, absolute (psia).
Base temperature means 60 °F.
Certificate of calibration means a document stating the base prover volume and other physical data required for the calibration of flow meters.
Composite meter factor means a meter factor corrected from normal operating pressure to base pressure. The composite meter factor is determined by proving operations where the pressure is considered constant during the measurement period between provings.
Configuration log means the list of constant flow parameters, calculation methods, alarm set points, and other values that are programmed into the flow computer in a CMS.
Coriolis meter means a device which by means of the interaction between a flowing fluid and oscillation of tube(s) infers a mass flow rate. The meter also infers the density by measuring the natural frequency of the oscillating tubes. The Coriolis meter consists of sensors and a transmitter, which convert the output from the sensors to signals representing volume and density.
Coriolis measurement system (CMS) means a metering system using a Coriolis meter in conjunction with a tertiary device, pressure transducer, and temperature transducer in order to derive and report gross standard oil volume. A CMS system provides real-time, on-line measurement of oil.
Displacement prover means a prover consisting of a pipe or pipes with known capacities, a displacement device, and detector switches, which sense when the displacement device has reached the beginning and ending points of the calibrated section of pipe. Displacement provers can be portable or fixed.
Dynamic meter factor means a kinetic meter factor derived by linear interpolation or polynomial fit, used for conditions where a series of meter factors have been determined over a range of normal operating conditions.
Event log means an electronic record of all exceptions and changes to the flow parameters contained within the configuration log that occur and have an impact on a quantity transaction record.
Gross standard volume means a volume of oil corrected to base pressure and temperature.
Indicated volume means the uncorrected volume indicated by the meter in a lease automatic custody transfer system or the Coriolis meter in a CMS. For a positive displacement meter, the indicated volume is represented by the non-resettable totalizer on the meter head. For Coriolis meters, the indicated volume is the uncorrected (without the meter factor) mass of liquid divided by the density.
Innage gauging means the level of a liquid in a tank measured from the datum plate or tank bottom to the surface of the liquid.
Lease automatic custody transfer (LACT) system means a system of components designed to provide for the unattended custody transfer of oil produced from a lease(s), unit PA(s), or CA(s) to the transporting carrier while providing a proper and accurate means for determining the net standard volume and quality, and fail-safe and tamper-proof operations.
Master meter prover means a positive displacement meter or Coriolis meter that is selected, maintained, and operated to serve as the reference device for the proving of another meter. A comparison of the master meter to the Facility Measurement Point (FMP) line meter output is the basis of the master-meter method.
Meter factor means a ratio obtained by dividing the measured volume of liquid that passed through a prover or master meter during the proving by the measured volume of liquid that passed through the line meter during the proving, corrected to base pressure and temperature.
Net standard volume means the gross standard volume corrected for quantities of non-merchantable substances such as sediment and water.
Outage gauging means the distance from the surface of the liquid in a tank to the reference gauge point of the tank.
Positive displacement meter means a meter that registers the volume passing through the meter using a system which constantly and mechanically isolates the flowing liquid into segments of known volume.
Quantity transaction record (QTR) means a report generated by CMS equipment that summarizes the daily and hourly gross standard volume calculated by the flow computer and the average or totals of the dynamic data that is used in the calculation of gross standard volume.
Tertiary device means, for a CMS, the flow computer and associated memory, calculation, and display functions.
Transducer means an electronic device that converts a physical property, such as pressure, temperature, or electrical resistance, into an electrical output signal that varies proportionally with the magnitude of the physical property. Typical output signals are in the form of electrical potential (volts), current (milliamps), or digital pressure or temperature readings. The term transducer includes devices commonly referred to as transmitters.
Vapor tight means capable of holding pressure differential only slightly higher than that of installed pressure-relieving or vapor recovery devices.
(b) As used in this subpart, the following acronyms carry the meaning prescribed:
API means American Petroleum Institute.
CA has the meaning set forth in § 3170.3 of this part.
COA has the meaning set forth in § 3170.3 of this part.
CPL means correction for the effect of pressure on a liquid.
CTL means correction for the effect of temperature on a liquid.
NIST means National Institute of Standards and Technology.
PA has the meaning set forth in § 3170.3 of this part.
PMT means Production Measurement Team.
PSIA means pounds per square inch, absolute.
S&W means sediment and water.
This subpart is established pursuant to the authority granted to the Secretary of the Interior through various Federal and Indian mineral leasing statutes and the Federal Oil and Gas Royalty Management Act of 1982. This 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. More specifically, this subpart implements and supplements the provisions of 43 CFR 3162.1, 3162.5-1(a), (c), and (d), 3162.5-2(a), and 3162.5-3.
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.
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.
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.
The regulations in this part apply to:
(a) All Federal onshore and Indian oil and gas leases (other than those of the Osage Tribe);
(b) Indian Mineral Development Act (IMDA) agreements for oil and gas, unless specifically excluded in the agreement or unless the relevant provisions of the rule are inconsistent with the agreement;
(c) Leases and other business agreements 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;
(d) State or private tracts committed to a federally approved unit or communitization agreement (CA) as defined by or established under 43 CFR subpart 3105 or 43 CFR part 3180; and
(e) All onshore facility measurement points where oil or gas produced from the leases or agreements identified earlier in this section is measured.
The purpose of this subpart is to state the application requirements for the approval of all proposed oil and gas and service wells, certain subsequent well operations, and abandonment.
This subpart details the Bureau's uniform national standards for the minimum levels of performance expected from lessees and operators when conducting drilling operations on Federal and Indian lands (except Osage Tribe) and for abandonment immediately following drilling. The purpose also is to identify the enforcement actions that will result when violations of the minimum standards are found, and when those violations are not abated in a timely manner.
(a) All lines entering or leaving any oil storage tank must have valves capable of being effectively sealed during the production and sales phases unless otherwise provided under this subpart. During the production phase, all appropriate valves that allow unmeasured production to be removed from storage must be effectively sealed in the closed position. During any other phase (sales, water drain, or hot oiling), and prior to taking the top tank gauge measurement, all appropriate valves that allow unmeasured production to enter or leave the sales tank must be effectively sealed in the closed position (see Appendix A to subpart 3173). Each unsealed or ineffectively sealed appropriate valve is a separate violation.
(b) Valves or combinations of valves and tanks that provide access to the production before it is measured for sales are considered appropriate valves and are subject to the seal requirements of this subpart (see Appendix A to subpart 3173). If there is more than one valve on a line from a tank, the valve closest to the tank must be sealed. All appropriate valves must be in an operable condition and accurately reflect whether the valve is open or closed.
(c) The following are not considered appropriate valves and are not subject to the sealing requirements of this subpart:
(1) Valves on production equipment ( e.g., separator, dehydrator, gun barrel, or wash tank);
(2) Valves on water tanks, provided that the possibility of access to production in the sales and storage tanks does not exist through a common circulating, drain, overflow, or equalizer system;
(3) Valves on tanks that contain oil that has been determined by the AO or AR to be waste or slop oil;
(4) Sample cock valves used on piping or tanks with a Nominal Pipe Size of 1 inch or less in diameter;
(5) Fill-line valves during shipment when a single tank with a nominal capacity of 500 barrels (bbl) or less is used for collecting marginal production of oil produced from a single well ( i.e., production that is less than 3 bbl per day). All other seal requirements of this subpart apply;
(6) Gas line valves used on piping with a Nominal Pipe Size of 1 inch or less used as tank bottom “roll” lines, provided there is no access to the contents of the storage tank and the roll lines cannot be used as equalizer lines;
(7) Valves on tank heating systems that use a fluid other than the contents of the storage tank ( i.e., steam, water, or glycol);
(8) Valves used on piping with a Nominal Pipe Size of 1 inch or less connected directly to the pump body or used on pump bleed off lines;
(9) Tank vent-line valves; and
(10) Sales, equalizer, or fill-line valves on systems where production may be removed only through approved oil metering systems ( e.g., LACT or CMS). However, any valve that allows access for removing oil before it is measured through the metering system must be effectively sealed (see Appendix A to subpart 3173).
(d) Tampering with any appropriate valve is prohibited. Tampering with an appropriate valve may result in an assessment of civil penalties for knowingly or willfully preparing, maintaining, or submitting false, inaccurate, or misleading reports, records, or written information under 30 U.S.C. 1719(d)(1) and 43 CFR 3163.2(f)(1), or knowingly or willfully taking, removing, transporting, using, or diverting oil or gas from a lease site without valid legal authority under 30 U.S.C. 1719(d)(2) and 43 CFR 3163.2(f)(2), together with any other remedies provided by law.
(a) Oil may be stored only in tanks that meet the requirements of § 3174.5(b) of this subpart.
(b) Oil must be measured on the lease, unit PA, or CA, unless approval for off-lease measurement is obtained under §§ 3173.22 and 3173.23 of this part.
(c) Oil produced from a lease, unit PA, or CA may not be commingled with production from other leases, unit PAs, or CAs or non-Federal properties before the point of royalty measurement, unless prior approval is obtained under §§ 3173.14 and 3173.15 of this part.
(d) An operator must obtain a BLM-approved FMP number under §§ 3173.12 and 3173.13 of this part for each oil measurement facility where the measurement affects the calculation of the volume or quality of production on which royalty is owed ( i.e., oil tank used for tank gauging, LACT system, CMS, or other approved metering device), except as provided in paragraph (h) of this section.
(e) Except as provided in paragraph (h) of this section, all equipment used to measure the volume of oil for royalty purposes installed after January 17, 2017 must comply with the requirements of this subpart.
(f) Except as provided in paragraph (h) of this section, measuring procedures and equipment used to measure oil for royalty purposes, that is in use on January 17, 2017, must comply with the requirements of this subpart on or before the date the operator is required to apply for an FMP number under 3173.12(e) of this part. Prior to that date, measuring procedures and equipment used to measure oil for royalty purposes, that is in use on January 17, 2017 must continue to comply with the requirements of Onshore Oil and Gas Order No. 4, Measurement of oil, § 3164.1(b) as contained in 43 CFR part 3160, (revised October 1, 2016), and any COAs and written orders applicable to that equipment.
(g) The requirement to follow the approved equipment lists identified in §§ 3174.6(b)(5)(ii)(A), 3174.6(b)(5)(iii), 3174.8(a)(1), and 3174.9(a) does not apply until January 17, 2019. The operator or manufacturer must obtain approval of a particular make, model, and size by submitting the test data used to develop performance specifications to the PMT to review.
(h) Meters used for allocation under a commingling and allocation approval under § 3173.14 are not required to meet the requirements of this subpart.
The purpose of this subpart is to protect public health and safety and those personnel essential to maintaining control of the well. This subpart identifies the Bureau of Land Management's uniform national requirements and minimum standards of performance expected from operators when conducting operations involving oil or gas that is known or could reasonably be expected to contain hydrogen sulfide (H 2 S) or which results in the emission of sulfur dioxide (SO 2 ) as a result of flaring H 2 S. This subpart also identifies the gravity of violations, probable corrective action(s), and normal abatement periods.
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.
(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.
(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.
(a) As used in this part, the term:
Allocated or allocation means a method or process by which production is measured at a central point and apportioned to the individual lease, or unit Participating Area (PA), or CA from which the production originated.
API (followed by a number) means the American Petroleum Institute Manual of Petroleum Measurement Standards, with the number referring to the Chapter and Section in that manual.
Audit trail means all source records necessary to verify and recalculate the volume and quality of oil or gas production measured at a facility measurement point (FMP) and reported to the Office of Natural Resources Revenue (ONRR).
Authorized officer (AO) has the same meaning as defined in 43 CFR 3000.0-5.
Averaging period means the previous 12 months or the life of the meter, whichever is shorter. For FMPs that measure production from a newly drilled well, the averaging period excludes production from that well that occurred in or before the first full month of production. (For example, if an oil FMP and a gas FMP were installed to measure only the production from a new well that first produced on April 10, the averaging period for this FMP would not include the production that occurred in April (partial month) and May (full month) of that year.)
Bias means a shift in the mean value of a set of measurements away from the true value of what is being measured.
By-pass means any piping or other arrangement around or avoiding a meter or other measuring device or method (or component thereof) at an FMP that allows oil or gas to flow without measurement. Equipment that permits the changing of the orifice plate of a gas meter without bleeding the pressure off the gas meter run ( e.g., senior fitting) is not considered to be a by-pass.
Commingling, for production accounting and reporting purposes, means combining, before the point of royalty measurement, production from more than one lease, unit PA, or CA, or production from one or more leases, unit PAs, or CAs with production from State, local governmental, or private properties that are outside the boundaries of those leases, unit PAs, or CAs. Combining production from multiple wells within a single lease, unit PA, or CA, or combining production downhole from different geologic formations within the same lease, unit PA, or CA, is not considered commingling for production accounting purposes.
Communitized area means the area committed to a BLM approved communitization agreement.
Communitization agreement (CA) means an agreement to combine a lease or a portion of a lease that cannot otherwise be independently developed and operated in conformity with an established well spacing or well development program, with other tracts for purposes of cooperative development and operations.
Condition of Approval (COA) means a site-specific requirement included in the approval of an application that may limit or modify the specific actions covered by the application. Conditions of approval may minimize, mitigate, or prevent impacts to public lands or resources.
Days means consecutive calendar days, unless otherwise indicated.
Facility means:
(i) A site and associated equipment used to process, treat, store, or measure production from or allocated to a Federal or Indian lease, unit PA, or CA that is located upstream of or at (and including) the approved point of royalty measurement; and
(ii) A site and associated equipment used to store, measure, or dispose of produced water that is located on a lease, unit, or communitized area.
Facility measurement point (FMP) means a BLM-approved point where oil or gas produced from a Federal or Indian lease, unit PA, or CA is measured and the measurement affects the calculation of the volume or quality of production on which royalty is owed. FMP includes, but is not limited to, the approved point of royalty measurement and measurement points relevant to determining the allocation of production to Federal or Indian leases, unit PAs, or CAs. However, allocation facilities that are part of a commingling and allocation approval under § 3173.15 or that are part of a commingling and allocation approval approved after July 9, 2013, are not FMPs. An FMP also includes a meter or measurement facility used in the determination of the volume or quality of royalty-bearing oil or gas produced before BLM approval of an FMP under § 3173.12. An FMP must be located on the lease, unit, or communitized area unless the BLM approves measurement off the lease, unit, or CA. The BLM will not approve a gas processing plant tailgate meter located off the lease, unit, or CA, as an FMP.
Gas means any fluid, either combustible or noncombustible, hydrocarbon or non-hydrocarbon, that has neither independent shape nor volume, but tends to expand indefinitely and exists in a gaseous state under metered temperature and pressure conditions.
Incident of Noncompliance (INC) means documentation that the BLM issues that identifies violations and notifies the recipient of the notice of required corrective actions.
Lease has the same meaning as defined in 43 CFR 3160.0-5.
Lessee has the same meaning as defined in 43 CFR 3160.0-5.
NIST traceable means an unbroken and documented chain of comparisons relating measurements from field or laboratory instruments to a known standard maintained by the National Institute of Standards and Technology (NIST).
Notice to lessees and operators (NTL) has the same meaning as defined in 43 CFR 3160.0-5.
Off-lease measurement means measurement at an FMP that is not located on the lease, unit, or communitized area from which the production came.
Oil means a mixture of hydrocarbons that exists in the liquid phase at the temperature and pressure at which it is measured. Condensate is considered to be oil for purposes of this part. Gas liquids extracted from a gas stream upstream of the approved point of royalty measurement are considered to be oil for purposes of this part.
(i) Clean oil or Pipeline oil means oil that is of such quality that it is acceptable to normal purchasers.
(ii) Slop oil means oil that is of such quality that it is not acceptable to normal purchasers and is usually sold to oil reclaimers. Oil that can be made acceptable to normal purchasers through special treatment that can be economically provided at existing or modified facilities or using portable equipment at or upstream of the FMP is not slop oil.
(iii) Waste oil means oil that has been determined by the AO or authorized representative to be of such quality that it cannot be treated economically and put in a marketable condition with existing or modified lease facilities or portable equipment, cannot be sold to reclaimers, and has been determined by the AO to have no economic value.
Operator has the same meaning as defined in 43 CFR 3160.0-5.
Participating area (PA) has the same meaning as defined in 43 CFR 3180.0-5.
Point of royalty measurement means a BLM-approved FMP at which the volume and quality of oil or gas which is subject to royalty is measured. The point of royalty measurement is to be distinguished from meters that determine only the allocation of production to particular leases, unit PAs, CAs, or non-Federal and non-Indian properties. The point of royalty measurement is also known as the point of royalty settlement.
Production means oil or gas removed from a well bore and any products derived therefrom.
Production Measurement Team (PMT) means a panel of members from the BLM (which may include BLM-contracted experts) that reviews changes in industry measurement technology, methods, and standards to determine whether regulations should be updated, and provides guidance on measurement technologies and methods not addressed in current regulation. The purpose of the PMT is to act as a central advisory body to ensure that oil and gas produced from Federal and Indian leases is accurately measured and properly reported.
Purchaser means any person or entity who legally takes ownership of oil or gas in exchange for financial or other consideration.
Source record means any unedited and original record, document, or data that is used to determine volume and quality of production, regardless of format or how it was created or stored ( e.g., paper or electronic). It includes, but is not limited to, raw and unprocessed data ( e.g., instantaneous and continuous information used by flow computers to calculate volumes); gas charts; measurement tickets; calibration, verification, prover, and configuration reports; pumper and gauger field logs; volume statements; event logs; seal records; and gas analyses.
Statistically significant describes a difference between two data sets that exceeds the threshold of significance.
Tampering means any deliberate adjustment or alteration to a meter or measurement device, appropriate valve, or measurement process that could introduce bias into the measurement or affect the BLM's ability to independently verify volumes or qualities reported.
Threshold of significance means the maximum difference between two data sets (a and b) that can be attributed to uncertainty effects. The threshold of significance is determined as follows:
Where:
T s = Threshold of significance, in percent
U a = Uncertainty (95 percent confidence) of data set a, in percent
U b = Uncertainty (95 percent confidence) of data set b, in percent
Total observed volume (TOV) means the total measured volume of all oil, sludges, sediment and water, and free water at the measured or observed temperature and pressure.
Transporter means any person or entity who legally moves or transports oil or gas from an FMP.
Uncertainty means the statistical range of error that can be expected between a measured value and the true value of what is being measured. Uncertainty is determined at a 95 percent confidence level for the purposes of this part.
Unit means the land within a unit area as defined in 43 CFR 3180.0-5.
Unit PA means the unit participating area, if one is in effect, the exploratory unit if there is no associated participating area, or an enhanced recovery unit.
Variance means an approved alternative to a provision or standard of a regulation, Onshore Oil and Gas Order, or NTL.
(b) As used in this part, the following additional acronyms apply:
API means American Petroleum Institute.
BLM means the Bureau of Land Management.
Btu means British thermal unit.
CMS means Coriolis Measurement System.
LACT means lease automatic custody transfer.
OGOR means Oil and Gas Operations Report (Form ONRR-4054 or any successor report).
ONRR means the Office of Natural Resources Revenue, U.S. Department of the Interior, and includes any successor agency.
S&W means sediment and water.
WIS means Well Information System or any successor electronic filing system.
This subpart applies to all onshore leases of Federal and Indian oil and gas (other than those of the Osage Tribe). It also applies to Indian Mineral Development Act agreements. For proposed operations on a committed State or fee tract in a federally supervised unit or communitized tract, the operator must furnish a copy of the approved State permit to the authorized officer of the BLM which will be accepted for record purposes.
This subpart is applicable to all onshore Federal and Indian (except Osage Tribe) oil and gas leases.
(a) Components used for quantity or quality determination of oil must be effectively sealed to indicate tampering, including, but not limited to, the following components of LACT meters (see § 3174.8(a)) and CMSs (see § 3174.9(e)):
(1) Sample probe;
(2) Sampler volume control;
(3) All valves on lines entering or leaving the sample container, excluding the safety pop-off valve (if so equipped). Each valve must be sealed in the open or closed position, as appropriate;
(4) Meter assembly, including the counter head and meter head;
(5) Temperature averager;
(6) LACT meters or CMS;
(7) Back pressure valve pressure adjustment downstream of the meter;
(8) Any drain valves in the system;
(9) Manual-sampling valves (if so equipped);
(10) Valves on diverter lines larger than 1 inch in nominal diameter;
(11) Right-angle drive;
(12) Totalizer; and
(13) Prover connections.
(b) Each missing or ineffectively sealed component is a separate violation.
(a) Certain material specified in this section is incorporated by reference into this part with the approval of the Director of the Federal Register under 5 U.S.C. 552(a) and 1 CFR part 51. Operators must comply with all incorporated standards and material, as they are listed in this section. 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 material is available for inspection at the Bureau of Land Management, Division of Fluid Minerals, 20 M Street SE., Washington, DC 20003, 202-912-7162; at all BLM offices with jurisdiction over oil and gas activities; and is available from the sources listed below. It is also available for inspection at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202-741-6030 or go to http://www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html .
(b) American Petroleum Institute (API), 1220 L Street NW., Washington, DC 20005; telephone 202-682-8000; API also offers free, read-only access to some of the material at http://publications.api.org .
(1) API Manual of Petroleum Measurement Standards (MPMS) Chapter 2—Tank Calibration, Section 2A, Measurement and Calibration of Upright Cylindrical Tanks by the Manual Tank Strapping Method; First Edition, February 1995; Reaffirmed February 2012 (“API 2.2A”), IBR approved for § 3174.5(c).
(2) API MPMS Chapter 2—Tank Calibration, Section 2.2B, Calibration of Upright Cylindrical Tanks Using the Optical Reference Line Method; First Edition, March 1989, Reaffirmed January 2013 (“API 2.2B”), IBR approved for § 3174.5(c).
(3) API MPMS Chapter 2—Tank Calibration, Section 2C, Calibration of Upright Cylindrical Tanks Using the Optical-triangulation Method; First Edition, January 2002; Reaffirmed May 2008 (“API 2.2C”), IBR approved for § 3174.5(c).
(4) API MPMS Chapter 3, Section 1A, Standard Practice for the Manual Gauging of Petroleum and Petroleum Products; Third Edition, August 2013 (“API 3.1A”), IBR approved for §§ 3174.5(b), 3174.6(b).
(5) API MPMS Chapter 3—Tank Gauging, Section 1B, Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic Tank Gauging; Second Edition, June 2001; Reaffirmed August 2011 (“API 3.1B”), IBR approved for § 3174.6(b).
(6) API MPMS Chapter 3—Tank Gauging, Section 6, Measurement of Liquid Hydrocarbons by Hybrid Tank Measurement Systems; First Edition, February 2001; Errata September 2005; Reaffirmed October 2011 (“API 3.6”), IBR approved for § 3174.6(b).
(7) API MPMS Chapter 4—Proving Systems, Section 1, Introduction; Third Edition, February 2005; Reaffirmed June 2014 (“API 4.1”), IBR approved for § 3174.11(c).
(8) API MPMS Chapter 4—Proving Systems, Section 2, Displacement Provers; Third Edition, September 2003; Reaffirmed March 2011, Addendum February 2015 (“API 4.2”), IBR approved for §§ 3174.11(b) and (c).
(9) API MPMS Chapter 4, Section 5, Master-Meter Provers; Fourth Edition, June 2016, (“API 4.5”), IBR approved for § 3174.11(b).
(10) API MPMS Chapter 4—Proving Systems, Section 6, Pulse Interpolation; Second Edition, May 1999; Errata April 2007; Reaffirmed October 2013 (“API 4.6”), IBR approved for § 3174.11(c).
(11) API MPMS Chapter 4, Section 8, Operation of Proving Systems; Second Edition, September 2013 (“API 4.8”), IBR approved for § 3174.11(b).
(12) API MPMS Chapter 4—Proving Systems, Section 9, Methods of Calibration for Displacement and Volumetric Tank Provers, Part 2, Determination of the Volume of Displacement and Tank Provers by the Waterdraw Method of Calibration; First Edition, December 2005; Reaffirmed July 2015 (“API 4.9.2”), IBR approved for § 3174.11(b).
(13) API MPMS Chapter 5—Metering, Section 6, Measurement of Liquid Hydrocarbons by Coriolis Meters; First Edition, October 2002; Reaffirmed November 2013 (“API 5.6”), IBR approved for §§ 3174.9(e), 3174.11(h) and (i).
(14) API MPMS Chapter 6—Metering Assemblies, Section 1, Lease Automatic Custody Transfer (LACT) Systems; Second Edition, May 1991; Reaffirmed May 2012 (“API 6.1”), IBR approved for § 3174.8(a) and (b).
(15) API MPMS Chapter 7, Temperature Determination; First Edition, June 2001, Reaffirmed February 2012 (“API 7”), IBR approved for §§ 3174.6(b), 3174.8(b).
(16) API MPMS Chapter 7.3, Temperature Determination—Fixed Automatic Tank Temperature Systems; Second Edition, October 2011 (“API 7.3”), IBR approved for § 3174.6(b).
(17) API MPMS Chapter 8, Section 1, Standard Practice for Manual Sampling of Petroleum and Petroleum Products; Fourth Edition, October 2013 (“API 8.1”), IBR approved for §§ 3174.6(b), 3174.11(h).
(18) API MPMS Chapter 8, Section 2, Standard Practice for Automatic Sampling of Petroleum and Petroleum Products; Third Edition, October 2015 (“API 8.2”), IBR approved for §§ 3174.6(b), 3174.8(b), 3174.11(h).
(19) API MPMS Chapter 8—Sampling, Section 3, Standard Practice for Mixing and Handling of Liquid Samples of Petroleum and Petroleum Products; First Edition, October 1995; Errata March 1996; Reaffirmed, March 2010 (“API 8.3”), IBR approved for §§ 3174.8(b), 3174.11(h).
(20) API MPMS Chapter 9, Section 1, Standard Test Method for Density, Relative Density, or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method; Third Edition, December 2012 (“API 9.1”), IBR approved for §§ 3174.6(b), 3174.8(b).
(21) API MPMS Chapter 9, Section 2, Standard Test Method for Density or Relative Density of Light Hydrocarbons by Pressure Hydrometer; Third Edition, December 2012 (“API 9.2”), IBR approved for §§ 3174.6(b), 3174.8(b).
(22) API MPMS Chapter 9, Section 3, Standard Test Method for Density, Relative Density, and API Gravity of Crude Petroleum and Liquid Petroleum Products by Thermohydrometer Method; Third Edition, December 2012 (“API 9.3”), IBR approved for §§ 3174.6(b), 3174.8(b).
(23) API MPMS Chapter 10, Section 4, Determination of Water and/or Sediment in Crude Oil by the Centrifuge Method (Field Procedure); Fourth Edition, October 2013; Errata March 2015 (“API 10.4”), IBR approved for §§ 3174.6(b), 3174.8(b).
(24) API MPMS Chapter 11—Physical Properties Data, Section 1, Temperature and Pressure Volume Correction Factors for Generalized Crude Oils, Refined Products and Lubricating Oils; May 2004, Addendum 1 September 2007; Reaffirmed August 2012 (“API 11.1”), IBR approved for §§ 3174.9(f), 3174.12(a).
(25) API MPMS Chapter 12—Calculation of Petroleum Quantities, Section 2, Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 1, Introduction; Second Edition, May 1995; Reaffirmed March 2014 (“API 12.2.1”), IBR approved for §§ 3174.8(b), 3174.9(g).
(26) API MPMS Chapter 12—Calculation of Petroleum Quantities, Section 2, Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 2, Measurement Tickets; Third Edition, June 2003; Reaffirmed September 2010 (“API 12.2.2”), IBR approved for §§ 3174.8(b), 3174.9(g).
(27) API MPMS Chapter 12—Calculation of Petroleum Quantities, Section 2, Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 3, Proving Report; First Edition, October 1998; Reaffirmed March 2009 (“API 12.2.3”), IBR approved for § 3174.11(c) and (i).
(28) API MPMS Chapter 12—Calculation of Petroleum Quantities, Section 2, Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 4, Calculation of Base Prover Volumes by the Waterdraw Method; First Edition, December 1997; Reaffirmed March 2009; Errata July 2009 (“API 12.2.4”), IBR approved for § 3174.11(b).
(29) API MPMS Chapter 13—Statistical Aspects of Measuring and Sampling, Section 1, Statistical Concepts and Procedures in Measurements; First Edition, June 1985 Reaffirmed February 2011; Errata July 2013 (“API 13.1”), IBR approved for § 3174.4(a).
(30) API MPMS Chapter 13, Section 3, Measurement Uncertainty; First Edition, May, 2016 (“API 13.3”), IBR approved for § 3174.4(a).
(31) API MPMS Chapter 14, Section 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids—Concentric, Square-edged Orifice Meters, Part 1, General Equations and Uncertainty Guidelines; Fourth Edition, September 2012; Errata July 2013 (“API 14.3.1”), IBR approved for § 3174.4(a).
(32) API MPMS Chapter 18—Custody Transfer, Section 1, Measurement Procedures for Crude Oil Gathered From Small Tanks by Truck; Second Edition, April 1997; Reaffirmed February 2012 (“API 18.1”), IBR approved for § 3174.6(b).
(33) API MPMS Chapter 18, Section 2, Custody Transfer of Crude Oil from Lease Tanks Using Alternative Measurement Methods, First Edition, July 2016 (“API 18.2”), IBR approved for § 3174.6(b).
(34) API MPMS Chapter 21—Flow Measurement Using Electronic Metering Systems, Section 2, Electronic Liquid Volume Measurement Using Positive Displacement and Turbine Meters; First Edition, June 1998; Reaffirmed August 2011 (“API 21.2”), IBR approved for §§ 3174.8(b), 3174.9(f), 3174.10(f).
(35) API Recommended Practice (RP) 12R1, Setting, Maintenance, Inspection, Operation and Repair of Tanks in Production Service; Fifth Edition, August 1997; Reaffirmed April 2008 (“API RP 12R1”), IBR approved for § 3174.5(b).
(36) API RP 2556, Correction Gauge Tables For Incrustation; Second Edition, August 1993; Reaffirmed November 2013 (“API RP 2556”), IBR approved for § 3174.5(c).
Note 1 to § 3174.3( b ):
You may also be able to purchase these standards from the following resellers: Techstreet, 3916 Ranchero Drive, Ann Arbor, MI 48108; telephone 734-780-8000; www.techstreet.com/api/apigate.html ; IHS Inc., 321 Inverness Drive South, Englewood, CO 80112; 303-790-0600; www.ihs.com ; SAI Global, 610 Winters Avenue, Paramus, NJ 07652; telephone 201-986-1131; http://infostore.saiglobal.com/store/ .
(a) This subpart is applicable to all onshore Federal and Indian (except Osage Tribe) oil and gas leases when drilling, completing, testing, reworking, producing, injecting, gathering, storing, or treating operations are being conducted in zones which are known or could reasonably be expected to contain H 2 S or which, when flared, could produce SO 2 , in such concentrations that upon release could constitute a hazard to human life. The requirements and minimum standards of this subpart do not apply when operating in zones where H 2 S is presently known not to be present or cannot reasonably be expected to be present in concentrations of 100 parts per million (ppm) or more in the gas stream.
(b) The requirements and minimum standards in this subpart do not relieve an operator from compliance with any applicable Federal, State, or local requirement(s) regarding H 2 S or SO 2 which are more stringent.
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.
(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.
(a) All by-passes are prohibited.
(b) Tampering with any measurement device, component of a measurement device, or measurement process is prohibited.
(c) Any by-pass or tampering with a measurement device, component of a measurement device, or measurement process may, together with any other remedies provided by law, result in an assessment of civil penalties for knowingly or willfully:
(1) Taking, removing, transporting, using, or diverting oil or gas from a lease site without valid legal authority under 30 U.S.C. 1719(d)(2) and 43 CFR 3163.2(f)(2); or
(2) Preparing, maintaining, or submitting false, inaccurate, or misleading reports, records, or information under 30 U.S.C. 1719(d)(1) and 43 CFR 3163.2(f)(1).
As used in this subpart, the following definitions apply:
Best Management Practices (BMP) means practices that provide for state-of-the-art mitigation of specific impacts that result from surface operations. Best Management Practices are voluntary unless they have been analyzed as a mitigation measure in the environmental review for a Master Development Plan, Application for Permit to Drill (APD), Right-of-Way, or other related facility and included as a Condition of Approval.
Blooie line means a discharge line used in conjunction with a rotating head in drilling operations when air or gas is used as the circulating medium.
Casual use means activities involving practices that do not ordinarily lead to any appreciable disturbance or damage to lands, resources, or improvements. This term does not apply to private surface. Casual use includes surveying activities.
Complete APD means that the information in the APD package is accurate and addresses all of the requirements of this subpart. The onsite inspection verifies important information that is part of the APD package and is a critical step in determining if the package is complete. Therefore, the onsite inspection must be conducted, and any deficiencies identified at the onsite corrected, before the APD package can be considered to be complete. While cultural, biological, or other inventories and environmental assessments (EA) or environmental impact statements (EIS) may be required to approve the APD, they are not required before an APD package is considered to be complete.
(1) The APD package must contain:
(i) A completed Form 3160-3 (Application for Permit to Drill or Reenter) (see 43 CFR 3162.3-1(d));
(ii) A well plat certified by a registered surveyor with a surveyor's original stamp (see § 3171.6(b));
(iii) A drilling plan (see 43 CFR 3162.3-1(d) and 3171.7);
(iv) A Surface Use Plan of Operations (see 43 CFR 3162.3-1(d) and 3171.8);
(v) Evidence of bond coverage (see 43 CFR 3162.3-1(d) and 3171.9);
(vi) Operator certification with original signature (see § 3171.10); and
(vii) Other information that may be required by order or notice (see 43 CFR 3162.3-1(d)(4)).
(2) The BLM and the surface managing agency, as appropriate, will review the APD package and determine that the drilling plan, the Surface Use Plan of Operations, and other information that the BLM may require (43 CFR 3162.3-1(d)(4)), including the well location plat and geospatial databases, completely describe the proposed action.
Condition of Approval (COA) means a site-specific requirement included in an approved APD or Sundry Notice that may limit or amend the specific actions proposed by the operator. Conditions of Approval minimize, mitigate, or prevent impacts to public lands or other resources. Best Management Practices may be incorporated as a Condition of Approval.
Days means all calendar days including holidays.
Emergency repairs means actions necessary to correct an unforeseen problem that could cause or threaten immediate substantial adverse impact on public health and safety or the environment.
Geospatial database means a set of georeferenced computer data that contains both spatial and attribute data. The spatial data defines the geometry of the object and the attribute data defines all other characteristics.
Indian lands means any lands or interest in lands of an Indian tribe or an Indian allottee held in trust by the United States or which is subject to a Federal restriction against alienation.
Indian oil and gas means any oil and gas interest of an Indian tribe or on allotted lands where the interest is held in trust by the United States or is subject to Federal restrictions against alienation. It does not include minerals subject to the provisions of section 3 of the Act of June 28, 1906 (34 Stat. 539), but does include oil and gas on lands administered by the United States under section 14(g) of Public Law 92-203, as amended.
Master Development Plan means information common to multiple planned wells, including drilling plans, Surface Use Plans of Operations, and plans for future production.
National Forest System lands means those Federal lands administered by the U.S. Forest Service, such as the National Forests and the National Grasslands.
Onsite inspection means an inspection of the proposed drill pad, access road, flowline route, and any associated Right-of-Way or Special Use Authorization needed for support facilities, conducted before the approval of the APD or Surface Use Plan of Operations and construction activities.
Private surface owner means a non-Federal or non-State owner of the surface estate and includes any Indian owner of surface estate not held in trust by the United States.
Reclamation means returning disturbed land as near to its predisturbed condition as is reasonably practical.
Split estate means lands where the surface is owned by an entity or person other than the owner of the Federal or Indian oil and gas.
Surface managing agency means any Federal or State agency having jurisdiction over the surface overlying Federal or Indian oil and gas.
Variance means an approved alternative to a provision or standard of an order or Notice to Lessee.
(a) If an operator chooses to use higher rated equipment than that authorized in the Application for Permit to Drill (APD), testing procedures shall apply to the approved working pressures, not the upgraded higher working pressures.
(b) Some situations may exist either on a well-by-well or field-wide basis whereby it is commonly accepted practice to vary a particular minimum standard(s) established in this subpart. This situation may be resolved by requesting a variance (see § 3172.13), by the inclusion of a stipulation to the APD, or by the issuance of a Notice to Lessees and Operators (NTL) by the appropriate BLM office.
(c) When a violation is discovered, and if it does not cause or threaten immediate substantial and adverse impact on public health and safety, the environment, production accountability or royalty income, it will be classified as minor. The violation may be reissued as a major violation if not corrected during the abatement period and continued drilling has changed the adverse impact of the violation so that it meets the specific definition of a major violation.
(d) This subpart is not intended to circumvent the reporting requirements or compliance aspects that may be stated elsewhere in existing NTLs, regulations, etc. A lessee's compliance with the requirements of the regulations in this subpart shall not relieve the lessee of the obligation to comply with other applicable laws and regulations in accordance with 43 CFR 3162.5-1(c). Lessees should give special attention to the automatic assessment provisions in 43 CFR 3163.1(b).
(e) This subpart is based upon the assumption that operations have been approved in accordance with 43 CFR part 3160 and subpart 3171 of this part. Failure to obtain approval prior to commencement of drilling or related operations shall subject the operator to immediate assessment under 43 CFR 3163.1(b)(2).
(a) In addition to any INC issued for a seal violation, the AO or AR may place one or more Federal seals on any appropriate valve, sealing device, or oil-metering-system component that does not comply with the requirements in §§ 3173.2 and 3173.3 if the operator is not present, refuses to cooperate with the AO or AR, or is unable to correct the noncompliance.
(b) The placement of a Federal seal does not constitute compliance with the requirements of §§ 3173.2 and 3173.3.
(c) A Federal seal may not be removed without the approval of the AO or AR.
(a) Volume measurement uncertainty levels. (1) The FMP must achieve the following overall uncertainty levels as calculated in accordance with statistical concepts described in API 13.1, the methodologies in API 13.3, and the quadrature sum (square root of the sum of the squares) method described in API 14.3.1, Subsection 12.3 (all incorporated by reference, see § 3174.3) or other methods approved under paragraph (d):
Table 1 to § 3174.4—Volume Measurement Uncertainty Levels
If the averaging period volume (see definition 43 CFR 3170.3) is:
The overall volume measurement uncertainty must be within:
1. Greater than or equal to 30,000 bbl/month
±0.50 percent.
2. Less than 30,000 bbl/month
±1.50 percent.
(2) Only a BLM State Director may grant an exception to the uncertainty levels prescribed in paragraph (a)(1) of this section, and only upon:
(i) A showing that meeting the required uncertainly level would involve extraordinary cost or unacceptable adverse environmental effects; and
(ii) Written concurrence of the PMT, prepared in coordination with the Deputy Director.
(b) Bias. The measuring equipment used for volume determinations must achieve measurement without statistically significant bias.
(c) Verifiability. All FMP equipment must be susceptible to independent verification by the BLM of the accuracy and validity of all inputs, factors, and equations that are used to determine quantity or quality. Verifiability includes the ability to independently recalculate volume and quality based on source records.
(d) Alternative equipment. The PMT will make a determination under § 3174.13 of this subpart regarding whether proposed alternative equipment or measurement procedures meet or exceed the objectives and intent of this section.
As used in this subpart, the term:
Authorized officer means any employee of the Bureau of Land Management authorized to perform the duties described in 43 CFR parts 3000 and 3100 (43 CFR 3000.0-5).
Christmas tree means an assembly of valves and fittings used to control production and provide access to the producing tubing string. The assembly includes all equipment above the tubinghead top flange.
Dispersion technique means a mathematical representation of the physical and chemical transportation, dilution, and transformation of H 2 S gas emitted into the atmosphere.
Escape rate means that the maximum volume (Q) used as the escape rate in determining the radius of exposure shall be that specified in paragraphs (1) through (4) of this definition, as applicable:
(1) For a production facility, the escape rate shall be calculated using the maximum daily rate of gas produced through that facility or the best estimate thereof;
(2) For gas wells, the escape rate shall be calculated by using the current daily absolute open-flow rate against atmospheric pressure;
(3) For oil wells, the escape rate shall be calculated by multiplying the producing gas/oil ratio by the maximum daily production rate or best estimate thereof; or
(4) For a well being drilled in a developed area, the escape rate may be determined by using the offset wells completed in the interval(s) in question.
Essential personnel means those on-site personnel directly associated with the operation being conducted and necessary to maintain control of the well.
Exploratory well means any well drilled beyond the known producing limits of a pool.
Gas well means a well for which the energy equivalent of the gas produced, including the entrained liquid hydrocarbons, exceeds the energy equivalent of the oil produced.
H 2 S Drilling Operations Plan means a written plan which provides for safety of essential personnel and for maintaining control of the well with regard to H 2 S and SO 2.
Lessee means a person or entity holding record title in a lease issued by the United States (43 CFR 3160.0-5).
Major violation means noncompliance which causes or threatens immediate. substantial, and adverse impacts on public health and safety, the environment, production accountability, or royalty income (43 CFR 3160.0-5).
Minor violation means noncompliance which does not rise to the level of a major violation (43 CFR 3160.0-5).
Oil well means a well for which the energy equivalent of the oil produced exceeds the energy equivalent of the gas produced, including the entrained liquid hydrocarbons.
Operating rights owner means a person or entity holding operating rights in a lease issued by the United States. A lessee may also be an operating rights owner if the operating rights in a lease or portion thereof have not been severed from record title (43 CFR 3160.0-5).
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 he/she is responsible under the terms of the lease for the operations conducted on the leased lands or a portion thereof (43 CFR 3160.0-5).
Potentially hazardous volume means a volume of gas of such H 2 S concentration and flow rate that it may result in radius of exposure-calculated ambient concentrations of 100 ppm H 2 S at any occupied residence, school, church, park, school bus stop, place of business, or other area where the public could reasonably be expected to frequent, or 500 ppm H 2 S at any Federal, State, County, or municipal road or highway.
Production facilities means any wellhead, flowline, piping, treating, or separating equipment, water disposal pits, processing plant, or combination thereof prior to the approved measurement point for any lease, communitization agreement, or unit participating area.
Prompt correction means immediate correction of violations, with operation suspended if required at the discretion of the authorized officer.
Public Protection Plan means a written plan which provides for the safety of the potentially affected public with regard to H 2 S and SO 2.
Radius of exposure means the calculation resulting from using the following Pasquill-Gifford derived equation, or by such other method(s) as may be approved by the authorized officer:
(1) For determining the 100 ppm radius of exposure where the H 2 S concentration in the gas stream is less than 10:
X = [1.589)(H 2 S concentration)(Q)]
(0.6258) ; or
(2) For determining the 500 ppm radius of exposure where the H 2 S concentration in the gas stream is less than 10:
X = [(0.4546)(H 2 S concentration)(Q)]
(0.6258)
Where:
X = radius of exposure in feet;
H 2 S Concentration = decimal equivalent of the mole or volume fractions of H 2 S in the gaseous mixture; and
Q = maximum volume of gas determined to be available for escape in cubic feet per day (at standard conditions of 14.73 psia and 60 °F).
(3) For determining the 100 ppm or the 500 ppm radius of exposure in gas streams containing H 2 S concentrations of 10 percent or greater, a dispersion technique that takes into account representative wind speed, direction, atmospheric stability, complex terrain, and other dispersion features shall be utilized. Such techniques may include, but shall not be limited to, one of a series of computer models outlined in the Environmental Protection Agency's “Guidelines on Air Quality Models” (EPA-450/2-78-027R).
(4) Where multiple H 2 S sources ( i.e., wells, treatment equipment, flowlines, etc.) are present, the operator may elect to utilize a radius of exposure which covers a larger area than would be calculated using radius of exposure formula for each component part of the drilling/completion/workover/production system.
(5) For a well being drilled in an area where insufficient data exits to calculate a radius of exposure, but where H 2 S could reasonably be expected to be present in concentrations in excess of 100 ppm in the gas stream, a 100 ppm radius of exposure equal to 3,000 feet shall be assumed.
Zones known not to contain H 2 S means geological formations in a field where prior drilling, logging, coring, testing, or producing operations have confirmed the absence of H 2 S-bearing zones that contain 100 ppm or more of H 2 S in the gas stream.
Zones known to contain H 2 S means geological formations in a field where prior drilling, logging, coring, testing, or producing operations have confirmed that H 2 S-bearing zones will be encountered that contain 100 ppm or more of H 2 S in the gas stream.
Zones which can reasonably be expected to contain H 2 S means geological formations in the area which have not had prior drilling, but prior drilling to the same formations in similar field(s) within the same geologic basin indicates there is a potential for 100 ppm or more of H 2 S in the gas stream.
Zones which cannot reasonably be expected to contain H 2 S means geological formations in the area which have not had prior drilling, but prior drilling to the same formations in similar field(s) within the same geologic basin indicates there is not a potential for 100 ppm or more of H 2 S in the gas stream.
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.
(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.
An Application for Permit to Drill or Reenter, on Form 3160-3, is required for each proposed well, and for reentry of existing wells (including disposal and service wells), to develop an onshore lease for Federal or Indian oil and gas.
(a) Where to file. On or after March 13, 2017, the operator must file an APD and associated documents using the BLM's electronic commerce application for oil and gas permitting and reporting. The operator may contact the local BLM Field Office for information on how to gain access to the electronic commerce application. Prior to March 13, 2017, an operator may file an APD and associated documents in the BLM Field Office having jurisdiction over the application.
(b) Early notification. The operator may wish to contact the BLM and any applicable surface managing agency, as well as all private surface owners, to request an initial planning conference as soon as the operator has identified a potential area of development. Early notification is voluntary and would precede the Notice of Staking option or filing of an APD. It allows the involved surface managing agency or private surface owner to apprise the prospective operator of any unusual conditions on the lease area. Early notification also provides both the surface managing agency or private surface owner and the prospective operator with the earliest possible identification of seasonal restrictions and determination of potential areas of conflict. The prospective operator should have a map of the proposed project available for surface managing agency review to determine if a cultural or biological inventory or other information may be required. Inventories are not the responsibility of the operator.
(c) Notice of Staking option. (1) Before filing an APD or Master Development Plan, the operator may file a Notice of Staking with the BLM. The purpose of the Notice of Staking is to provide the operator with an opportunity to gather information to better address site-specific resource concerns while preparing the APD package. This may expedite approval of the APD. On or after March 13, 2017, if an operator chooses to file a Notice of Staking (NOS), the operator must file the NOS using the BLM's electronic commerce application for oil and gas permitting and reporting. Attachment I, Sample Format for Notice of Staking, provides the information required for the Notice of Staking option. Prior to March 13, 2017, an operator may file a Notice of Staking in the BLM Field Office having jurisdiction.
(2) For Federal lands managed by other surface managing agencies, the BLM will provide a copy of the Notice of Staking to the appropriate surface managing agency office. In Alaska, when a subsistence stipulation is part of the lease, the operator must also send a copy of the Notice of Staking to the appropriate Borough and/or Native Regional or Village Corporation.
(3) Within 10 days of receiving the Notice of Staking, the BLM or the FS will review it for required information and schedule a date for the onsite inspection. The onsite inspection will be conducted as soon as weather and other conditions permit. The operator must stake the proposed drill pad and ancillary facilities, and flag new or reconstructed access routes, before the onsite inspection. The staking must include a center stake for the proposed well, two reference stakes, and a flagged access road centerline. Staking activities are considered casual use unless the particular activity is likely to cause more than negligible disturbance or damage. Offroad vehicular use for the purposes of staking is casual use unless, in a particular case, it is likely to cause more than negligible disturbance or damage, or otherwise prohibited.
(4) On non-NFS lands, the BLM will invite the surface managing agency and private surface owner, if applicable, to participate in the onsite inspection. If the surface is privately owned, the operator must furnish to the BLM the name, address, and telephone number of the surface owner if known. All parties who attend the onsite inspection will jointly develop a list of resource concerns that the operator must address in the APD. The operator will be provided a list of these concerns either during the onsite inspection or within 7 days of the onsite inspection. Surface owner concerns will be considered to the extent practical within the law. Failure to submit an APD within 60 days of the onsite inspection will result in the Notice of Staking being returned to the operator.
As used in this subpart, the term:
2M, 3M, 5M, 10M, and 15M mean the pressure ratings used for equipment with a working pressure rating of the equivalent thousand pounds per square inch (psi) (2M=2,000 psi, 3M=3,000 psi, etc.).
Abnormal pressure zone means a zone that has either pressure above or below the normal gradient for an area and/or depth.
Bleed line means the vent line that bypasses the chokes in the choke manifold system; also referred to as panic line.
Blooie line means a discharge line used in conjunction with a rotating head.
Drilling spool means a connection component with both ends either flanged or hubbed, with an internal diameter at least equal to the bore of the casing, and with smaller side outlets for connecting auxiliary lines.
Exploratory well means any well drilled beyond the known producing limits of a pool.
Fill-up line means the line used to fill the hole when the drill pipe is being removed from the well. It is usually connected to a 2-inch collar that is welded into a drilling nipple.
Flare line means a line used to carry gas away from the rig to be burned at a safer location. The gas comes from the degasser, gas buster, separator, or when drill stem testing, directly from the drill pipe.
Functionally operated means activating equipment without subjecting it to well-bore pressure.
Isolating means using cement to protect, separate, or segregate usable water and mineral resources.
Lease means any contract, profit-share agreement, joint venture, or other agreement issued or approved by the United States under a mineral leasing law that authorizes exploration for, extraction of, or removal of oil or gas (see 43 CFR 3160.0-5).
Lessee means a person holding record title in a lease issued by the United States (see 43 CFR 3160.0-5).
Make-up water means water that is used in mixing slurry for cement jobs and plugging operations and is compatible with the cement constituents being used.
Manual locking device means any manually activated device, such as a hand wheel, etc., that is used for the purpose of locking the preventer in the closed position.
Mud for plugging purposes means a slurry of bentonite or similar flocculent/viscosifier, water, and additives needed to achieve the desired weight and consistency to stabilize the hole.
Mudding up means adding materials and chemicals to water to control the viscosity, weight, and filtrate loss of the circulating system.
Operating rights owner (or owner) means a person or entity holding operating rights in a lease issued by the United States. A lessee also may be an operating rights owner if the operating rights in a lease or portion thereof have not been severed from record title.
Operational means capable of functioning as designed and installed without undue force or further modification.
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 his/her responsibility for the operations conducted in the leased lands or a portion thereof.
Precharge pressure means the nitrogen pressure remaining in the accumulator after all the hydraulic fluid has been expelled from beneath the movable barrier.
Prompt correction means immediate correction of violations, with drilling suspended if required in the discretion of the authorized officer.
Prospectively valuable deposit of minerals means any deposit of minerals that the authorized officer determines to have characteristics of quantity and quality that warrant its protection.
Tagging the plug means running in the hole with a string of tubing or drill pipe and placing sufficient weight on the plug to ensure its integrity. Other methods of tagging the plug may be approved by the authorized officer.
Targeted tee or turn means a fitting used in pressure piping in which a bull plug or blind flange of the same pressure rating as the rest of the approved system is installed at the end of a tee or cross, opposite the fluid entry arm, to change the direction of flow and to reduce erosion.
Usable water means generally those waters containing up to 10,000 parts per million (ppm) of total dissolved solids.
Weep hole means a small hole that allows pressure to bleed off through the metal plate used in covering well bores after abandonment operations.
(a) When a single truck load constitutes a completed sale, the driver must possess documentation containing the information required in § 3174.12.
(b) When multiple truckloads are involved in a sale and the oil measurement method is based on the difference between the opening and closing gauges, the driver of the last truck must possess the documentation containing the information required in § 3174.12. All other drivers involved in the sale must possess a trip log or manifest.
(c) After the seals have been broken, the purchaser or transporter is responsible for the entire contents of the tank until it is resealed.
(a) Measurement objective. Oil measurement by tank gauging must accurately compute the total net standard volume of oil withdrawn from a properly calibrated sales tank by following the activities prescribed in § 3174.6 and the requirements of § 3174.4 of this subpart to determine the quantity and quality of oil being removed.
(b) Oil tank equipment. (1) Each tank used for oil storage must comply with the recommended practices listed in API RP 12R1 (incorporated by reference, see § 3174.3).
(2) Each oil storage tank must be connected, maintained, and operated in compliance with §§ 3173.2, 3173.6, and 3173.7 of this part.
(3) All oil storage tanks, hatches, connections, and other access points must be vapor tight. Unless connected to a vapor recovery or flare system, all tanks must have a pressure-vacuum relief valve installed at the highest point in the vent line or connection with another tank. All hatches, connections, and other access points must be installed and maintained in accordance with manufacturers' specifications.
(4) All oil storage tanks must be clearly identified and have an operator-generated number unique to the lease, unit PA, or CA, stenciled on the tank and maintained in a legible condition.
(5) Each oil storage tank associated with an approved FMP that has a tank-gauging system must be set and maintained level.
(6) Each oil storage tank associated with an approved FMP that has a tank-gauging system must be equipped with a distinct gauging reference point, consistent with API 3.1A (incorporated by reference, see § 3174.3). The height of the reference point must be stamped on a fixed bench-mark plate or stenciled on the tank near the gauging hatch, and be maintained in a legible condition.
(c) Sales tank calibrations. The operator must accurately calibrate each oil storage tank associated with an approved FMP that has a tank-gauging system using either API 2.2A, API 2.2B, or API 2.2C; and API RP 2556 (all incorporated by reference, see § 3174.3). The operator must:
(1) Determine sales tank capacities by tank calibration using actual tank measurements;
(i) The unit volume must be in barrels (bbl); and
(ii) The incremental height measurement must match gauging increments specified in § 3174.6(b)(5)(i)(C);
(2) Recalibrate a sales tank if it is relocated or repaired, or the capacity is changed as a result of denting, damage, installation, removal of interior components, or other alterations; and
(3) Submit sales tank calibration charts (tank tables) to the AO within 45 days after calibration. Tank tables may be in paper or electronic format.
The requirements of this subpart are the minimum acceptable standards with regard to H 2 S operations. This subpart also classifies violations as typically major or minor for purposes of the assessment and penalty provisions of 43 CFR part 3160, subpart 3163, specifies the corrective action which will probably be required, and establishes the normal abatement period following detection of a major or minor violation in which the violator may take such corrective action without incurring an assessment. However, the authorized officer may, after consideration of all appropriate factors, require reasonable and necessary standards, corrective actions, and abatement periods that may, in some cases, vary from those specified in this subpart that he/she determines to be necessary to protect public health and safety, the environment, or to maintain control of a well to prevent waste of Federal mineral resources. To the extent such standards, actions, or abatement periods differ from those set forth in this subpart, they may be subject to review pursuant to 43 CFR 3165.3.
(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.
(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.
(a) Any party subject to a requirement of a regulation in this part may request a variance from that requirement.
(1) A request for a variance must include the following:
(i) Identification of the specific requirement from which the variance is requested;
(ii) Identification of the length of time for which the variance is requested, if applicable;
(iii) An explanation of the need for the variance;
(iv) A detailed description of the proposed alternative means of compliance;
(v) A showing that the proposed alternative means of compliance will produce a result that meets or exceeds the objectives of the applicable requirement for which the variance is requested; and
(vi) The FMP number(s) for which the variance is requested, if applicable.
(2) A request for a variance must be submitted as a separate document from any plans or applications. A request for a variance that is submitted as part of a master development plan, application for permit to drill, right-of-way application, or application for approval of other types of operations, rather than submitted separately, will not be considered. Approval of a plan or application that contains a request for a variance does not constitute approval of the variance. A separate request for a variance may be submitted simultaneously with a plan or application. For plans or applications that are contingent upon the approval of the variance request, the BLM encourages the simultaneous submission of the variance request and the plan or application.
(3) The party requesting the variance must file the request and any supporting documents using WIS. If electronic filing is not possible or practical, the operator may submit a request for variance on the Form 3160-5, Sundry Notices and Reports on Wells (Sundry Notice) to the BLM Field Office having jurisdiction over the lands described in the application.
(4) The AO, after considering all relevant factors, may approve the variance, or approve it with COAs, only if the AO determines that:
(i) The proposed alternative means of compliance meets or exceeds the objectives of the applicable requirement(s) of the regulation;
(ii) Approving the variance will not adversely affect royalty income and production accountability; and
(iii) Issuing the variance is consistent with maximum ultimate economic recovery, as defined in 43 CFR 3160.0-5.
(5) The decision whether to grant or deny the variance request is entirely within the BLM's discretion.
(6) A variance from the requirements of a regulation in this part does not constitute a variance from provisions of other regulations, including Onshore Oil and Gas Orders.
(b) The BLM reserves the right to rescind a variance or modify any COA of a variance due to changes in Federal law, technology, regulation, BLM policy, field operations, noncompliance, or other reasons. The BLM will provide a written justification if it rescinds a variance or modifies a COA.
Operators are encouraged to consider and incorporate Best Management Practices into their APDs because Best Management Practices can result in reduced processing times and reduced number of Conditions of Approval. An APD package must include the following information that will be reviewed by technical specialists of the appropriate agencies to determine the technical adequacy of the package:
(a) A completed Form 3160-3; and
(b) A well plat. Operators must include in the APD package a well plat and geospatial database prepared by a registered surveyor depicting the proposed location of the well and identifying the points of control and datum used to establish the section lines or metes and bounds. The purpose of this plat is to ensure that operations are within the boundaries of the lease or agreement and that the depiction of these operations is accurately recorded both as to location (latitude and longitude) and in relation to the surrounding lease or agreement boundaries (public land survey corner and boundary ties). The registered surveyor should coordinate with the cadastral survey division of the appropriate BLM state office, particularly where the lands have not been surveyed under the Public Land Survey System.
(1) The plat and geospatial database must describe the location of operations in:
(i) Geographical coordinates generated by an electronic navigation system, and document the datum referenced to generate these coordinates; and
(ii) In feet and direction from the nearest two adjacent section lines, or, if not within the Rectangular Survey System, the nearest two adjacent property lines, generated from the BLM's current Geographic Coordinate Data Base.
(2) The surveyor who prepared the plat must sign it, certifying that the location has been staked on the ground as shown on the plat.
(3) Surveying and staking are necessary casual uses, typically involving negligible surface disturbance. The operator is responsible for making access arrangements with the appropriate Surface Managing Agency (other than the BLM and the FS) or private surface owner. On tribal or allotted lands, the operator must contact the appropriate office of the BIA to make access arrangements with the Indian surface owners. In the event that not all of the Indian owners consent or may be located, but a majority of those who can be located consent, or the owners of interests are so numerous that it would be impracticable to obtain their consent and the BIA finds that the issuance of the APD will cause no substantive injury to the land or any owner thereof, the BIA may approve access. Typical off-road vehicular use, when conducted in conjunction with these activities, is a necessary action for obtaining a permit and may be done without advance approval from the Surface Managing Agency, except for:
(i) Lands administered by the Department of Defense;
(ii) Other lands used for military purposes;
(iii) Indian lands; or
(iv) Where more than negligible surface disturbance is likely to occur or is otherwise prohibited.
(4) No entry on split estate lands for surveying and staking should occur without the operator first making a good faith effort to notify the surface owner. Also, operators are encouraged to notify the BLM or the FS, as appropriate, before entering private lands to stake for Federal mineral estate locations.
(a) Requirements. Blowout preventer (BOP) and related equipment (BOPE) shall be installed, used, maintained, and tested in a manner necessary to assure well control and shall be in place and operational prior to drilling the surface casing shoe unless otherwise approved by the APD. Commencement of drilling without the approved BOPE installed, unless otherwise approved, shall subject the operator to immediate assessment under 43 CFR 3163.1(b)(1). The BOP and related control equipment shall be suitable for operations in those areas which are subject to sub-freezing conditions. The BOPE shall be based on known or anticipated sub-surface pressures, geologic conditions, accepted engineering practice, and surface environment. Item number 7 of the 8 point plan in the APD specifically addresses expected pressures. The working pressure of all BOPE shall exceed the anticipated surface pressure to which it may be subjected, assuming a partially evacuated hole with a pressure gradient of 0.22 psi/ft.
(b) Violation classifications. The gravity of the violation for many of the well control minimum standards listed in paragraphs (b)(1) through (9) of this section are shown as minor. However, very short abatement periods in this subpart are often specified in recognition that by continuing to drill, the violation which was originally determined to be of a minor nature may cause or threaten immediate, substantial, and adverse impact on public health and safety, the environment, production accountability, or royalty income, which would require it reclassification as a major violation.
(1) Minimum standards and enforcement provisions for well control equipment. (i) A well control device shall be installed at the surface that is capable of complete closure of the well bore. This device shall be closed whenever the well is unattended.
Table 1 to § 3172.6( b )(1)( i )
Violation
Corrective action
Normal abatement period
Major
Install the equipment as specified
Prompt correction required.
(ii) For 2M system:
(A) Annular preventer, double ram, or two rams with one being blind and one being a pipe ram (major);
(B) Kill line (2 inch minimum);
(C) 1 kill line valve (2 inch minimum);
(D) 1 choke line valve;
(E) 2 chokes (refer to diagram in appendix A to this subpart);
(F) Upper kelly cock valve with handle available;
(G) Safety valve and subs to fit all drill strings in use;
(H) Pressure gauge on choke manifold;
(I) 2 inch minimum choke line; and
(J) Fill-up line above the uppermost preventer.
Table 2 to § 3172.6( b )(1)( ii )
Violation
Corrective action
Normal abatement period
Minor
Install the equipment as specified
24 hours.
Major (as indicated)
Install the equipment as specified
Prompt correction required.
(iii) For 3M system:
(A) Annular preventers (major);
(B) Double ram with blind rams and pipe rams (major);
(C) Drilling spool, or blowout preventer with 2 side outlets (choke side shall be a 3-inch minimum diameter, kill side shall be at least 2-inch diameter) (major);
(D) Kill line (2 inch minimum);
(E) A minimum of 2 choke line valves (3 inch minimum) (major);
(F) 3 inch diameter choke line;
(G) 2 kill line valves, one of which shall be a check valve (2 inch minimum) (major);
(H) 2 chokes (refer to diagram in appendix A to this subpart);
(I) Pressure gauge on choke manifold;
(J) Upper kelly cock valve with handle available;
(K) Safety valve and subs to fit all drill string connections in use;
(L) All BOPE connections subjected to well pressure shall be flanged, welded, or clamped (major); and
(M) Fill-up line above the uppermost preventer.
Table 3 to § 3172.6( b )(1)( iii )
Violation
Corrective action
Normal abatement period
Minor
Install the equipment as specified
24 hours.
Major (as indicated)
Install the equipment as specified
Prompt correction required.
(iv) For 5M system:
(A) Annular preventer (major);
(B) Pipe ram, blind ram, and, if conditions warrant, as specified by the authorized officer, another pipe ram shall also be required (major);
(C) A second pipe ram preventer or variable bore pipe ram preventer shall be used with a tapered drill string;
(D) Drilling spool, or blowout preventer with 2 side outlets (choke side shall be a 3-inch minimum diameter, kill side shall be at least 2-inch diameter) (major);
(E) 3 inch diameter choke line;
(F) 2 choke line valves (3 inch minimum) (major);
(G) Kill line (2 inch minimum);
(H) 2 chokes with 1 remotely controlled from rig floor (refer to diagram in appendix A to this subpart);
(I) 2 kill line valves and a check valve (2 inch minimum) (major);
(J) Upper kelly cock valve with a handle available;
(K) When the expected pressures approach working pressure of the system, 1 remote kill line tested to stack pressure (which shall run to the outer edge of the substructure and be unobstructed);
(L) Lower kelly cock valve with handle available;
(M) Safety valve(s) and subs to fit all drill string connections in use;
(N) Inside BOP or float sub available;
(O) Pressure gauge on choke manifold;
(P) All BOPE connections subjected to well pressure shall be flanged, welded, or clamped (major); and
(Q) Fill-up line above the uppermost preventer.
Table 4 to § 3172.6( b )(1)( iv )
Violation
Corrective action
Normal abatement period
Minor
Install the equipment as specified
24 hours.
Major (as indicated)
Install the equipment as specified
Prompt correction required.
(v) For 10M & 15M system:
(A) Annular preventer (major);
(B) 2 pipe rams (major);
(C) Blind rams (major);
(D) Drilling spool, or blowout preventer with 2 side outlets (choke side shall be a 3-inch minimum diameter, kill side shall be at least 2-inch diameter) (major):
(E) 3 inch choke line (major);
(F) 2 kill line valves (2 inch minimum) and check valve (major):
(G) Remote kill line (2 inch minimum) shall run to the outer edge of the substructure and be unobstructed;
(H) Manual and hydraulic choke line valves (3 inch minimum) (major);
(I) 3 chokes, 1 being remotely controlled (refer to diagram in appendix A to this subpart);
(J) Pressure gauge on choke manifold;
(K) Upper kelly cock valve with handle available;
(L) Lower kelly cock valve with handle available;
(M) Safety valves and subs to fit all drill string connections in use;
(N) Inside BOP or float sub available;
(O) Wear ring in casing head;
(P) All BOPE connections subjected to well pressure shall be flanged, welded, or clamped (major); and
(Q) Fill-up line installed above the uppermost preventer.
Table 5 to § 3172.6( b )(1)( v )
Violation
Corrective action
Normal abatement period
Minor
Install the equipment as specified
24 hours.
Major (as indicated)
Install the equipment as specified
Prompt correction required.
(vi) If repair or replacement of the BOPE is required after testing, this work shall be performed prior to drilling out the casing shoe.
Table 6 to § 3172.6( b )(1)( vi )
Violation
Corrective action
Normal abatement period
Major
Install the equipment as specified
Prompt correction required.
(vii) When the BOPE cannot function to secure the hole, the hole shall be secured using cement, retrievable packer or a bridge plug packer, bridge plug, or other acceptable approved method to assure safe well conditions.
Table 7 to § 3172.6( b )(1)( vii )
Violation
Corrective action
Normal abatement period
Major
Install the equipment as specified
Prompt correction required.
(2) Minimum standards and enforcement provisions for choke manifold equipment. (i) All choke lines shall be straight lines unless turns use tee blocks or are targeted with running tees, and shall be anchored to prevent whip and reduce vibration.
Table 8 to § 3172.6( b )(2)( i )
Violation
Corrective action
Normal abatement period
Minor
Install the equipment as specified
24 hours.
(ii) Choke manifold equipment configuration shall be functionally equivalent to the appropriate example diagram shown in appendix A of this subpart. The configuration of the chokes may vary.
Table 9 to § 3172.6( b )(2)( ii )
Violation
Corrective action
Normal abatement period
Minor
Install the equipment as specified
Prompt correction required.
(iii) All valves (except chokes) in the kill line, choke manifold, and choke line shall be a type that does not restrict the flow (full opening) and that allows a straight through flow (same enforcement as paragraph (b)(2)(ii) of this section).
(iv) Pressure gauges in the well control system shall be a type designed for drilling fluid service (same enforcement as paragraph (b)(2)(ii) of this section).
(3) Minimum standards and enforcement provisions for pressure accumulator system. (i) 2M system—accumulator shall have sufficient capacity to close all BOP's and retain 200 psi above precharge. Nitrogen bottles that meet manufacturer's specifications may be used as the backup to the required independent power source.
Table 10 to § 3172.6( b )(3)( i )
Violation
Corrective action
Normal abatement period
Minor
Install the equipment as specified
24 hours.
(ii) 3M system—accumulator shall have sufficient capacity to open the hydraulically controlled choke line valve (if so equipped), close all rams plus the annual preventer, and retain a minimum of 200 psi above precharge on the closing manifold without the use of the closing unit pumps. This is a minimum requirement. The fluid reservoir capacity shall be double the usable fluid volume of the accumulator system capacity and the fluid level of the reservoir shall be maintained at the manufacturer's recommendations. The 3M system shall have 2 independent power sources to close the preventers. Nitrogen bottles (3 minimum) may be 1 of the independent power sources and, if so, shall maintain a charge equal to the manufacturer's specifications.
Table 11 to § 3172.6( b )(3)( ii )
Violation
Corrective action
Normal abatement period
Minor
Install the equipment as specified
24 hours.
(iii) 5M and higher system—accumulator shall have sufficient capacity to open the hydraulically controlled gate valve (if so equipped) and close all rams plus the annular preventer (for 3 ram systems add a 50 percent safety factor to compensate for any fluid loss in the control system or preventers) and retain a minimum pressure of 200 psi above precharge on the closing manifold without use of the closing unit pumps. The fluid reservoir capacity shall be double the usable fluid volume of the accumulator system capacity and the fluid level of the reservoir shall be maintained at the manufacturer's recommendations. Two independent sources of power shall be available for powering the closing unit pumps. Sufficient nitrogen bottles are suitable as a backup power source only, and shall be recharged when the pressure falls below manufacturer's specifications.
Table 12 to § 3172.6( b )(3)( iii )
Violation
Corrective action
Normal abatement period
Minor
Install the equipment as specified
24 hours.
(4) Minimum standards and enforcement provisions for accumulator precharge pressure test. This test shall be conducted prior to connecting the closing unit to the BOP stack and at least once every 6 months. The accumulator pressure shall be corrected if the measured precharge pressure is found to be above or below the maximum or minimum limit specified in table 13 to this paragraph (b)(4) (only nitrogen gas may be used to precharge):
Table 13 to § 3172.6( b )(4)
Accumulator working
pressure rating
(psi)
Minimum acceptable
operating pressure
(psi)
Desired precharge
pressure
(psi)
Maximum acceptable
precharge pressure
(psi)
Minimum acceptable
precharge pressure
(psi)
1,500
1,500
750
800
700
2,000
2,000
1,000
1,100
900
3,000
3,000
1,000
1,100
900
Table 14 to § 3172.6( b )(4)
Violation
Corrective action
Normal abatement period
Minor
Perform test
24 hours.
(5) Minimum standards and enforcement provisions for power availability. Power for the closing unit pumps shall be available to the unit at all times so that the pumps shall automatically start when the closing unit manifold pressure has decreased to a pre-set level.
Table 15 to § 3172.6( b )(5)
Violation
Corrective action
Normal abatement period
Major
Install the equipment as specified
Prompt correction required.
(6) Minimum standards and enforcement provisions for accumulator pump capacity. Each BOP closing unit shall be equipped with sufficient number and sizes of pumps so that, with the accumulator system isolated from service, the pumps shall be capable of opening the hydraulically operated gate valve (if so equipped), plus closing the annular preventer on the smallest size drill pipe to be used within 2 minutes, and obtain a minimum of 200 psi above specified accumulator precharge pressure.
Table 16 to § 3172.6( b )(6)
Violation
Corrective action
Normal abatement period
Minor
Install the equipment as specified
24 hours.
(7) Minimum standards and enforcement provisions for locking devices. A manual locking device ( i.e., hand wheels) or automatic locking devices shall be installed on all systems of 2M or greater. A valve shall be installed in the closing line as close as possible to the annular preventer to act as a locking device. This valve shall be maintained in the open position and shall be closed only when the power source for the accumulator system is inoperative.
Table 17 to § 3172.6( b )(7)
Violation
Corrective action
Normal abatement period
Minor
Install the equipment as specified
24 hours.
(8) Minimum standards and enforcement provisions for remote controls. Remote controls shall be readily accessible to the driller. Remote controls for all 3M or greater systems shall be capable of closing all preventers. Remote controls for 5M or greater systems shall be capable of both opening and closing all preventers. Master controls shall be at the accumulator and shall be capable of opening and closing all preventers and the choke line valve (if so equipped). No remote control for a 2M system is required.
Table 18 to § 3172.6( b )(8)
Violation
Corrective action
Normal abatement period
Minor
Install the equipment as specified
24 hours.
(9) Minimum standards and enforcement provisions for well control equipment testing. (i) Perform all tests described in paragraphs (b)(9)(ii) through (x) of this section using clear water or an appropriate clear liquid for subfreezing temperatures with a viscosity similar to water.
(ii) Ram type preventers and associated equipment shall be tested to approved (see § 3172.4(a)) stack working pressure if isolated by test plug or to 70 percent of internal yield pressure of casing if BOP stack is not isolated from casing. Pressure shall be maintained for at least 10 minutes or until requirements of test are met, whichever is longer. If a test plug is utilized, no bleed-off of pressure is acceptable. For a test not utilizing a test plug, if a decline in pressure of more than 10 percent in 30 minutes occurs, the test shall be considered to have failed. Valve on casing head below test plug shall be open during test of BOP stack.
(iii) Annular type preventers shall be tested to 50 percent of rated working pressure. Pressure shall be maintained at least 10 minutes or until provisions of test are met, whichever is longer.
(iv) As a minimum, the test in paragraphs (b)(9)(ii) and (iii) of this section shall be performed:
(A) When initially installed;
(B) Whenever any seal subject to test pressure is broken;
(C) Following related repairs; and
(D) At 30-day intervals.
(v) Valves shall be tested from working pressure side during BOPE tests with all down stream valves open.
(vi) When testing the kill line valve(s), the check valve shall be held open or the ball removed.
(vii) Annular preventers shall be functionally operated at least weekly.
(viii) Pipe and blind rams shall be activated each trip, however, this function need not be performed more than once a day.
(ix) A BOPE pit level drill shall be conducted weekly for each drilling crew.
(x) Pressure tests shall apply to all related well control equipment.
(xi) All of the tests described in paragraphs (b)(9)(ii) through (x) of this section and/or drills shall be recorded in the drilling log.
Table 19 to § 3172.6( b )(9)
Violation
Corrective action
Normal abatement period
Minor
Perform the necessary test or provide documentation
24 hours or next trip, as most appropriate.
When water is drained from a production storage tank, the operator, purchaser, or transporter, as appropriate, must document the following information:
(a) Federal or Indian lease, unit PA, or CA number(s);
(b) The tank location by land description;
(c) The unique tank number and nominal capacity;
(d) Date of the opening gauge;
(e) Opening gauge (gauged manually or automatically), TOV, and free-water measurements, all to the nearest
1/2 inch;
(f) Unique identifying number of each seal removed;
(g) Closing gauge (gauged manually or automatically) and TOV measurement to the nearest
1/2 inch; and
(h) Unique identifying number of each seal installed.
(a) The procedures for oil measurement by tank gauging must comply with the requirements outlined in this section.
(b) The operator must follow the procedures identified in API 18.1 or API 18.2 (both incorporated by reference, see § 3174.3) as further specified in this paragraph to determine the quality and quantity of oil measured under field conditions at an FMP.
(1) Isolate tank. Isolate the tank for at least 30 minutes to allow contents to settle before proceeding with tank gauging operations. The tank isolating valves must be closed and sealed under § 3173.2 of this part.
(2) Determine opening oil temperature. Determination of the temperature of oil contained in a sales tank must comply with paragraphs (b)(2)(i) through (iii) of this section, API 7, and API 7.3 (both incorporated by reference, see § 3174.3). Opening temperature may be determined before, during, or after sampling.
(i) Glass thermometers must be clean, be free of fluid separation, have a minimum graduation of 1.0 °F, and have an accuracy of ±0.5 °F.
(ii) Electronic thermometers must have a minimum graduation of 0.1 °F and have an accuracy of ±0.5 °F.
(iii) Record the temperature to the nearest 1.0 °F for glass thermometers or 0.1 °F for portable electronic thermometers.
(3) Take oil samples. Sampling operations must be conducted prior to taking the opening gauge unless automatic sampling methods are being used. Sampling of oil removed from an FMP tank must yield a representative sample of the oil and its physical properties and must comply with API 8.1 or API 8.2 (both incorporated by reference, see § 3174.3).
(4) Determine observed oil gravity. Tests for oil gravity must comply with paragraphs (b)(4)(i) through (iii) of this section and API 9.1, API 9.2, or API 9.3 (all incorporated by reference, see § 3174.3).
(i) The hydrometer or thermohydrometer (as applicable) must be calibrated for an oil gravity range that includes the observed gravity of the oil sample being tested and must be clean, with a clearly legible oil gravity scale and with no loose shot weights.
(ii) Allow the temperature to stabilize for at least 5 minutes prior to reading the thermometer.
(iii) Read and record the observed API oil gravity to the nearest 0.1 degree. Read and record the temperature reading to the nearest 1.0 °F.
(5) Measure the opening tank fluid level. Take and record the opening gauge only after samples have been taken, unless automatic sampling methods are being used. Gauging must comply with either paragraph (b)(5)(i) of this section, API 3.1A, and API 18.1 (both incorporated by reference, see § 3174.3); or paragraph (b)(5)(ii) of this section, API 3.1B, API 3.6, and API 18.2 (all incorporated by reference, see § 3174.3); or paragraph (b)(5)(iii) of this section for dynamic volume determination.
(i) For manual gauging, comply with the requirements of API 3.1A and API 18.1 (both incorporated by reference, see § 3174.3) and the following:
(A) The proper bob must be used for the particular measurement method, i.e., either innage gauging or outage gauging;
(B) A gauging tape must be used. The gauging tape must be made of steel or corrosion-resistant material with graduation clearly legible, and must not be kinked or spliced;
(C) Either obtain two consecutive identical gauging measurements for any tank regardless of size, or:
( 1 ) For tanks of 1,000 bbl or less in capacity, three consecutive measurements that are within 1/4-inch of each other and average these three measurements to the nearest
1/4 inch; or
( 2 ) For tanks greater than 1,000 bbl in capacity, three consecutive measurements within
1/8 inch of each other, averaging these three measurements to the nearest
1/8 inch.
(D) A suitable product-indicating paste may be used on the tape to facilitate the reading. The use of chalk or talcum powder is prohibited; and
(E) The same tape and bob must be used for both opening and closing gauges.
(ii) For automatic tank gauging (ATG), comply with the requirements of API 3.1B, API 3.6, and API 18.2 (all incorporated by reference, see § 3174.3) and the following:
(A) The specific makes and models of ATG that are identified and described at www.blm.gov are approved for use;
(B) The ATG must be inspected and its accuracy verified to within ±
1/4 inch in accordance with API 3.1B, Subsection 9 (incorporated by reference, see § 3174.3) at least once a month or prior to sales, whichever is latest, or any time at the request of the AO. If the ATG is found to be out of tolerance, the ATG must be calibrated prior to sales; and
(C) A log of field verifications must be maintained and available upon request. The log must include the following information: The date of verification; the as-found manual gauge readings; the as-found ATG readings; and whether the ATG was field calibrated. If the ATG was field calibrated, the as-left manual gauge readings and as-left ATG readings must be recorded.
(iii) For dynamic volume determination under API 18.2, Subsection 10.1.1, (incorporated by reference, see § 3174.3), the specific makes and models of in-line meters that are identified and described at www.blm.gov are approved for use.
(6) Determine S&W content. Using the oil samples obtained pursuant to paragraph (b)(3) of this section, determine the S&W content of the oil in the sales tanks, according to API 10.4 (incorporated by reference, see § 3174.3).
(7) Transfer oil. Break the tank load line valve seal and transfer oil to the tanker truck. After transfer is complete, close the tank valve and seal the valve under §§ 3173.2 and 3173.5 of this part.
(8) Determine closing oil temperature. Determine the closing oil temperature using the procedures in paragraph (b)(2) of this section.
(9) Take closing gauge. Take the closing tank gauge using the procedures in paragraph (b)(5) of this section.
(10) Complete measurement ticket. Following procedures in § 3174.12.
(a) Drilling. For proposed drilling operations where formations will be penetrated which have zones known to contain or which could reasonably be expected to contain concentrations of H 2 S of 100 ppm or more in the gas stream, the H 2 S Drilling Operation Plan and, if the applicability criteria in § 3176.7(a) are met, a Public Protection Plan as outlined in § 3176.7(b), shall be submitted as part of the Application for Permit to Drill (APD) (refer to subpart 3171 of this part). In cases where multiple filings are being made with a single drilling plan, a single H 2 S Drilling Operations Plan and, if applicable, a single Public Protection Plan may be submitted for the lease, communitization agreement, unit, or field in accordance with subpart 3171. Failure to submit either the H 2 S Drilling Operations Plan or the Public Protection Plan when required by this subpart shall result in an incomplete APD pursuant to 43 CFR 3162.3-1.
(b) Drilling plan. The H 2 S Drilling Operations Plan shall fully describe the manner in which the requirements and minimum standards in § 3176.8, shall be met and implemented. As required by this subpart (§ 3176.8), the following must be submitted in the H 2 S Drilling Operations Plan:
(1) Statement that all personnel shall receive proper H 2 S training in accordance, with § 3176.8(c)(1).
(2) A legible well site diagram of accurate scale (may be included as part of the well site layout as required by subpart 3171 of this part) showing the following:
(i) Drill rig orientation;
(ii) Prevailing wind direction;
(iii) Terrain of surrounding area;
(iv) Location of all briefing areas (designate primary briefing area);
(v) Location of access road(s) (including secondary egress);
(vi) Location of flare line(s) and pit(s);
(vii) Location of caution and/or danger signs; and
(viii) Location of wind direction indicators.
(3) As required by this subpart, a complete description of the following H 2 S safety equipment/systems:
(i) Well control equipment. (A) Flare line(s) and means of ignition;
(B) Remote controlled choke;
(C) Flare gun/flares; and
(D) Mud-gas separator and rotating head (if exploratory well);
(ii) Protective equipment for essential personnel. (A) Location, type, storage, and maintenance of all working and escape breathing apparatus; and
(B) Means of communication when using protective breathing apparatus;
(iii) H 2 S detection and monitoring equipment. (A) H 2 S sensors and associated audible/visual alarm(s); and
(B) Portable H 2 S and SO 2 monitor(s);
(iv) Visual warning systems. (A) Wind direction indicators; and (B) Caution/danger sign(s) and flag(s);
(v) Mud program. (A) Mud system and additives; and (B) Mud degassing system;
(vi) Metallurgy. Metallurgical properties of all tubular goods and well control equipment which could be exposed to H 2 S (§ 3176.8(d)(3)); and
(vii) Communication. Means of communication from wellsite.
(4) Plans for well testing.
(c) Production. (1) For each existing production facility having an H 2 S concentration of 100 ppm or more in the gas stream, the operator shall calculate and submit the calculations to the authorized officer within 180 days of January 22, 1991, the 100 and, if applicable, the 500 ppm radii of exposure for all facilities to determine if the applicability criteria in § 3176.7(a) are met. Radii of exposure calculations shall not be required for oil or water flowlines. Further, if any of the applicability criteria (§ 3176.7(a)) are met, the operator shall submit a complete Public Protection Plan which meets the requirements of § 3176.7(b)(2) to the authorized officer within 1 year of January 22, 1991. For production facilities constructed after January 22, 1991, and meeting the minimum concentration (100 ppm in gas stream), the operator shall report the radii of exposure calculations, and if the applicability criteria in § 3176.7(a) are met, submit a complete Public Protection Plan (§ 3176.7(b)(2)) to the authorized officer within 60 days after completion of production facilities.
Table 1 to § 3176.6( c )(1)
Violation
Corrective action
Normal abatement period
Minor for failure to submit required information
Submit required information (radii of exposure and/or complete Public Protection Plan)
20 to 40 days.
(2) The operator shall initially test the H 2 S concentration of the gas stream for each well or production facility and shall make the results available to the authorized officer, upon request.
Table 2 to § 3176.6( c )(2)
Violation
Corrective action
Normal abatement period
Minor
Test gas from well or production facility
20 to 40 days.
(3) If operational or production alterations result in a 5 percent or more increase in the H 2 S concentration ( i.e., well recompletion, increased gas-to-oil ratios) or the radius of exposure as calculated under paragraph (c)(1) of this section, notification of such changes shall be submitted to the authorized officer within 60 days after identification of the change.
Table 3 to § 3176.6( c )(3)
Violation
Corrective action
Normal abatement period
Minor
Submit information to authorized officer
20 to 40 days.
(d) Plans and reports. (1) H 2 S Drilling Operations Plan(s) or Public Protection Plan(s) shall be reviewed by the operator on an annual basis and a copy of any necessary revisions shall be submitted to the authorized officer upon request.
Table 4 to § 3176.6( d )(1)
Violation
Corrective action
Normal abatement period
Minor
Submit information to authorized officer
20 to 40 days.
(2) Any release of a potentially hazardous volume of H 2 S shall be reported to the authorized officer as soon as practicable, but no later than 24 hours following identification of the release.
Table 5 to § 3176.6( d )(2)
Violation
Corrective action
Normal abatement period
Minor
Report undesirable event to the authorized officer
24 hours.
(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.
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.
(a) Lessees, operators, purchasers, transporters, and any other person directly involved in producing, transporting, purchasing, selling, or measuring oil or gas through the point of royalty measurement or the point of first sale, whichever is later, must retain all records, including source records, that are relevant to determining the quality, quantity, disposition, and verification of production attributable to Federal or Indian leases for the periods prescribed in paragraphs (c) through (e) of this section.
(b) This retention requirement applies to records generated during or for the period for which the lessee or operator has an interest in or conducted operations on the lease, or in which a person is involved in transporting, purchasing, or selling production from the lease.
(c) For Federal leases, and units or CAs that include Federal leases, but do not include Indian leases, the record holder must maintain records for:
(1) Seven years after the records are generated; unless,
(2) A judicial proceeding or demand involving such records is timely commenced, in which case the record holder must maintain such records until the final nonappealable decision in such judicial proceeding is made, or with respect to that demand is rendered, unless the Secretary or his/her designee or the applicable delegated State authorizes in writing an earlier release of the requirement to maintain such records.
(d) For Indian leases, and units or CAs that include Indian leases, but do not include Federal leases, the record holder must maintain records for:
(1) Six years after the records are generated; unless,
(2) The Secretary or his/her designee notifies the record holder that the Department of the Interior has initiated or is participating in an audit or investigation involving such records, in which case the record holder must maintain such records until the Secretary or his/her designee releases the record holder from the obligation to maintain the records.
(e) For units and communitized areas that include both Federal and Indian leases, 6 years after the records are generated. If the Secretary or his/her designee has notified the record holder within those 6 years that an audit or investigation involving such records has been initiated, then:
(1) If a judicial proceeding or demand is commenced within 7 years after the records are generated, the record holder must retain all records regarding production from the lease, unit PA, or CA until the final nonappealable decision in such judicial proceeding is made, or with respect to that demand is rendered, unless the Secretary or his/her designee authorizes in writing a release of the requirement to maintain such records before a final nonappealable decision is made or rendered.
(2) If a judicial proceeding or demand is not commenced within 7 years after the records are generated, the record holder must retain all records regarding production from the unit or communitized area until the Secretary or his/her designee releases the record holder from the obligation to maintain the records;
(f) The lessee, operator, purchaser, or transporter must maintain an audit trail.
(g) All records, including source records, that are used to determine quality, quantity, disposition, and verification of production attributable to a Federal or Indian lease, unit PA, or CA, must include the FMP number or the lease, unit PA, or CA number, along with a unique equipment identifier ( e.g., a unique tank identification number and meter station number), and the name of the company that created the record. For all facilities existing prior to the assignment of an FMP number, all records must include the following information:
(1) The name of the operator;
(2) The lease, unit PA, or CA number; and
(3) The well or facility name and number.
(h) Upon request of the AO, the operator, purchaser, or transporter must provide such records to the AO as may be required by regulation, written order, Onshore Order, NTL, or COA.
(i) All records must be legible.
(j) All records requiring a signature must also have the signer's printed name.
Cite this law
ONSHORE OIL AND GAS PRODUCTION (U.S.C.). Retrieved via LawPlayer, https://lawplayer.com/us/act/cfr-title-43-part-3170
United States government works (U.S. Code, Code of Federal Regulations) are in the public domain under 17 U.S.C. § 105.
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