Loading (50 kb)...'
(continued)
greater; $675 per year. The area subject to
annual rental includes the areal
extent of anchor chains, pipeline
risers, and other facilities and
devices associated with the
accessory.
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(c) If you hold a pipeline right-of-way that includes a site for an accessory to your pipeline and you are not covered by paragraph (b) of this section, then you must pay MMS an annual rental of $75 for use of the affected area.
(d) You may make the rental payments required by paragraphs (a), (b)(1), (b)(2), and (c) of this section on an annual basis, for a 5-year period, or for multiples of 5 years. You must make the first payment at the time you submit the pipeline right-of-way application. You must make all subsequent payments before the respective time periods begin.
(e) Late payments. An interest charge will be assessed on unpaid and underpaid amounts from the date the amounts are due, in accordance with the provisions found in 30 CFR 218.54. If you fail to make a payment that is late after written notice from MMS, MMS may initiate cancellation of the right-of-use grant and easement under 30 CFR 250.1013.
[68 FR 69312, Dec. 12, 2003, as amended at 69 FR 29433, May 24, 2004]
§ 250.1013 Grounds for forfeiture of pipeline right-of-way grants.
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Failure to comply with the Act, regulations, or any conditions of the right-of-way grant prescribed by the Regional Supervisor shall be grounds for forfeiture of the grant in an appropriate judicial proceeding instituted by the United States in any U.S. District Court having jurisdiction in accordance with the provisions of 43 U.S.C. 1349.
[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 55 FR 47753, Nov. 15, 1990; 59 FR 53094, Oct. 21, 1994; 62 FR 27955, May 22, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 63 FR 34597, June 25, 1998; 64 FR 9065, Feb. 24, 1999. Further redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003]
§ 250.1014 When pipeline right-of-way grants expire.
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Any right-of-way granted under the provisions of this subpart remains in effect as long as the associated pipeline is properly maintained and used for the purpose for which the grant was made, unless otherwise expressly stated in the grant. Temporary cessation or suspension of pipeline operations shall not cause the grant to expire. However, if the purpose of the grant ceases to exist or use of the associated pipeline is permanently discontinued for any reason, the grant shall be deemed to have expired.
[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 55 FR 47753, Nov. 15, 1990; 59 FR 53094, Oct. 21, 1994; 62 FR 27955, May 22, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 63 FR 34597, June 25, 1998; 64 FR 9065, Feb. 24, 1999. Further redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003]
§ 250.1015 Applications for pipeline right-of-way grants.
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(a) You must submit an original and three copies of an application for a new or modified pipeline ROW grant to the Regional Supervisor. The application must address those items required by §250.1007(a) or (b) of this subpart, as applicable. It must also state the primary purpose for which you will use the ROW grant. If the ROW has been used before the application is made, the application must state the date such use began, by whom, and the date the applicant obtained control of the improvement. When you file your application, you must pay the rental required under §250.1012 of this subpart, as well as the service fees listed in §250.125 of this part for a pipeline ROW grant to install a new pipeline, or to convert an existing lease term pipeline into a ROW pipeline. An application to modify an approved ROW grant must be accompanied by the additional rental required under §250.1012 if applicable. You must file a separate application for each ROW.
(b)(1) An individual applicant shall submit a statement of citizenship or nationality with the application. An applicant who is an alien lawfully admitted for permanent residence in the United States shall also submit evidence of such status with the application.
(2) If the applicant is an association (including a partnership), the application shall also be accompanied by a certified copy of the articles of association or appropriate reference to a copy of such articles already filed with MMS and a statement as to any subsequent amendments.
(3) If the applicant is a corporation, the application shall also include the following:
(i) A statement certified by the Secretary or Assistant Secretary of the corporation with the corporate seal showing the State in which it is incorporated and the name of the person(s) authorized to act on behalf of the corporation, or
(ii) In lieu of such a statement, an appropriate reference to statements or records previously submitted to MMS (including material submitted in compliance with prior regulations).
(c) The application shall include a list of every lessee and right-of-way holder whose lease or right-of-way is intersected by the proposed right-of-way. The application shall also include a statement that a copy of the application has been sent by registered or certified mail to each such lessee or right-of-way holder.
(d) The applicant shall include in the application an original and three copies of a completed Nondiscrimination in Employment form (YN 3341-1 dated July 1982). These forms are available at each MMS regional office.
(e) Notwithstanding the provisions of paragraph (a) of this section, the requirements to pay filing fees under that paragraph are suspended until January 3, 2006.
[53 FR 10690, Apr. 1, 1988, as amended at 62 FR 39775, July 24, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 64 FR 42598, Aug. 5, 1999. Further redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003; 70 FR 49876, Aug. 25, 2005; 70 FR 61893, Oct. 27, 2005]
§ 250.1016 Granting pipeline rights-of-way.
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(a) In considering an application for a right-of-way, the Regional Supervisor shall consider the potential effect of the associated pipeline on the human, marine, and coastal environments, life (including aquatic life), property, and mineral resources in the entire area during construction and operational phases. The Regional Supervisor shall prepare an environmental analysis in accordance with applicable policies and guidelines. To aid in the evaluation and determinations, the Regional Supervisor may request and consider views and recommendations of appropriate Federal Agencies, hold public meetings after appropriate notice, and consult, as appropriate, with State agencies, organizations, industries, and individuals. Before granting a pipeline right-of-way, the Regional Supervisor shall give consideration to any recommendation by the intergovernmental planning program, or similar process, for the assessment and management of OCS oil and gas transportation.
(b) Should the proposed route of a right-of-way adjoin and subsequently cross any State submerged lands, the applicant shall submit evidence to the Regional Supervisor that the State(s) so affected has reviewed the application. The applicant shall also submit any comment received as a result of that review. In the event of a State recommendation to relocate the proposed route, the Regional Supervisor may consult with the appropriate State officials.
(c)(1) The applicant shall submit photocopies of return receipts to the Regional Supervisor that indicate the date that each lessee or right-of-way holder referenced in §250.1010(c) of this part has received a copy of the application. Letters of no objection may be submitted in lieu of the return receipts.
(2) The Regional Supervisor shall not take final action on a right-of-way application until the Regional Supervisor is satisfied that each such lessee or right-of-way holder has been afforded at least 30 days from the date determined in paragraph (c)(1) of this section in which to submit comments.
(d) If a proposed right-of-way crosses any lands not subject to disposition by mineral leasing or restricted from oil and gas activities, it shall be rejected by the Regional Supervisor unless the Federal Agency with jurisdiction over such excluded or restricted area gives its consent to the granting of the right-of-way. In such case, the applicant, upon a request filed within 30 days after receipt of the notification of such rejection, shall be allowed an opportunity to eliminate the conflict.
(e)(1) If the application and other required information are found to be in compliance with applicable laws and regulations, the right-of-way may be granted. The Regional Supervisor may prescribe, as conditions to the right-of-way grant, stipulations necessary to protect human, marine, and coastal environments, life (including aquatic life), property, and mineral resources located on or adjacent to the right-of-way.
(2) If the Regional Supervisor determines that a change in the application should be made, the Regional Supervisor shall notify the applicant that an amended application shall be filed subject to stipulated changes. The Regional Supervisor shall determine whether the applicant shall deliver copies of the amended application to other parties for comment.
(3) A decision to reject an application shall be in writing and shall state the reasons for the rejection.
[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1988. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998. Further redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003]
§ 250.1017 Requirements for construction under pipeline right-of-way grants.
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(a) Failure to construct the associated right-of-way pipeline within 5 years of the date of the granting of a right-of-way shall cause the grant to expire.
(b)(1) A right-of-way holder shall ensure that the right-of-way pipeline is constructed in a manner that minimizes deviations from the right-of-way as granted.
(2) If, after constructing the right-of-way pipeline, it is determined that a deviation from the proposed right-of-way as granted has occurred, the right-of-way holder shall—
(i) Notify the operators of all leases and holders of all right-of-way grants in which a deviation has occurred, and within 60 days of the date of the acceptance by the Regional Supervisor of the completion of pipeline construction report, provide the Regional Supervisor with evidence of such notification; and
(ii) Relinquish any unused portion of the right-of-way.
(3) Substantial deviation of a right-of-way pipeline as constructed from the proposed right-of-way as granted may be grounds for forfeiture of the right-of-way.
(c) If the Regional Supervisor determines that a significant change in conditions has occurred subsequent to the granting of a right-of-way but prior to the commencement of construction of the associated pipeline, the Regional Supervisor may suspend or temporarily prohibit the commencement of construction until the right-of-way grant is modified to the extent necessary to address the changed conditions.
[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998. Further redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003]
§ 250.1018 Assignment of pipeline right-of-way grants.
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(a) Assignment may be made of a right-of-way grant, in whole or of any lineal segment thereof, subject to the approval of the Regional Supervisor. An application for approval of an assignment of a right-of-way or of a lineal segment thereof, shall be filed in triplicate with the Regional Supervisor.
(b) Any application for approval for an assignment, in whole or in part, of any right, title, or interest in a right-of-way grant must be accompanied by the same showing of qualifications of the assignees as is required of an applicant for a ROW in §250.1015 of this subpart and must be supported by a statement that the assignee agrees to comply with and to be bound by the terms and conditions of the ROW grant. The assignee must satisfy the bonding requirements in §250.1011 of this subpart. No transfer will be recognized unless and until it is first approved, in writing, by the Regional Supervisor. The assignee must pay the service fee listed in §250.125 of this part for a pipeline ROW assignment request.
(c) Notwithstanding the provisions of paragraph (b) of this section, the requirement to pay a filing fee under that paragraph is suspended until January 3, 2006.
[53 FR 10690, Apr. 1, 1988, as amended at 62 FR 39775, July 24, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998. Further redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003; 70 FR 61893, Oct. 27, 2005; 70 FR 49876, Aug. 25, 2005]
§ 250.1019 Relinquishment of pipeline right-of-way grants.
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A right-of-way grant or a portion thereof may be surrendered by the holder by filing a written relinquishment in triplicate with the Regional Supervisor. It must contain those items addressed in §§250.1751 and 250.1752 of this part. A relinquishment shall take effect on the date it is filed subject to the satisfaction of all outstanding debts, fees, or fines and the requirements in §250.1009(c)(9) of this part.
[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 67 FR 35406, May 17, 2002. Further redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003]
Subpart K—Oil and Gas Production Rates
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§ 250.1100 Definitions for production rates.
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Terms used in this subpart shall have meanings given below:
Enhanced recovery operations means pressure maintenance operations, secondary and tertiary recovery, cycling, and similar recovery operations which alter the natural forces in a reservoir to increase the ultimate recovery of oil or gas.
Gas reservoir means a reservoir that contains hydrocarbons predominantly in a gaseous (single-phase) state.
Gas-well completion means a well completed in a gas reservoir or in the gas cap of an oil reservoir with an associated gas cap.
Maximum Efficient Rate (MER) means the maximum sustainable daily oil or gas withdrawal rate from a reservoir which will permit economic development and depletion of that reservoir without detriment to ultimate recovery.
Maximum Production Rate (MPR) means the approved maximum daily rate at which oil or gas may be produced from a specified oil-well or gas-well completion.
Nonsensitive reservoir means a reservoir in which ultimate recovery is not decreased by high reservoir production rates.
Oil reservoir means a reservoir that contains hydrocarbons predominantly in a liquid (single-phase) state.
Oil reservoir with an associated gas cap means a reservoir that contains hydrocarbons in both a liquid and gaseous (two-phase) state.
Oil-well completion means a well completed in an oil reservoir or in the oil accumulation of an oil reservoir with an associated gas cap.
Sensitive reservoir means a reservoir in which ultimate recovery is decreased by high reservoir production rates. A high reservoir production rate is one which exceeds the MER.
Waste of oil and gas means: (1) The physical waste of oil and gas; (2) the inefficient, excessive, or improper use of, or the unnecessary dissipation of reservoir energy; (3) the locating, spacing, drilling, equipping, operating, or producing of any oil or gas well(s) in a manner which causes or tends to cause a reduction in the quantity of oil or gas ultimately recoverable from a pool under prudent and proper operations or which causes or tends to cause unnecessary or excessive surface loss or destruction of oil or gas; or (4) the inefficient storage of oil.
§ 250.1101 General requirements and classification of reservoirs.
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(a) Wells and reservoirs shall be produced at rates that will provide economic development and depletion of the hydrocarbon resources in a manner that would maximize the ultimate recovery without adversely affecting correlative rights.
(b) For directionally drilled wells in which the completed interval is closer than 500 feet from a unit or lease line or for vertically drilled wells in which the surface location is closer than 500 feet from a unit or lease line, for which the unit, lease, or royalty interests are not the same, the prior approval by the Regional Supervisor is required before production is commenced. An operator requesting such an approval shall furnish the Regional Supervisor with letters expressing acceptance or objection from operators of offset properties.
(c) The lessee shall propose a classification for each reservoir as an oil reservoir, an oil reservoir with an associated gas cap or a gas reservoir, and as sensitive or nonsensitive.
(d) All oil reservoirs with associated gas caps shall be initially classified as sensitive and shall require establishing a maximum efficient production rate and balancing of production in accordance with §250.1102(a) (1) and (5) of this part. All other oil reservoirs and all gas reservoirs shall be initially classified as nonsensitive.
(e) A reservoir may be reclassified by the Minerals Management Service (MMS) as to type and sensitivity at any time during its productive life when information becomes available showing that reclassification is warranted.
(f) The lessee must pay the service fee listed in §250.125 of this part with its request for either a 500 feet from lease/unit line production interval or to produce from a completion in an associated gas cap of a sensitive reservoir under this section.
[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 70 FR 49876, Aug. 25, 2005]
§ 250.1102 Oil and gas production rates.
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Link to an amendment published at 71 FR 19646, April 17, 2006.
(a) MER. (1) The lessee shall submit a proposed MER for each producing sensitive reservoir on Form MMS–127, Request for Reservoir Maximum Efficient Rate (MER), along with appropriate supporting information to the Regional Supervisor within 45 days after discovering that a reservoir is sensitive.
(2) The lessee may propose to revise an MER by submitting Form MMS–127 with appropriate supporting information.
(3) The effective date of an MER for a reservoir or revision thereof shall be the first day of the month in which Form MMS–127 is submitted.
(4) When approved, the MER shall not be exceeded, except as provided in paragraph (a)(5) of this section.
(5) If a reservoir is produced at a rate in excess of the MER for any month, the lessee should initiate measures necessary to balance production (offset overproduction by underproduction) during the next succeeding month. All overproduction shall be balanced by the end of the next succeeding calendar quarter following the quarter in which the overproduction occurred. Any operation in an overproduction status in any reservoir for two successive calendar quarters shall be shut in from that reservoir until the actual production is equal to that which would have occurred under the approved MER, unless an alternative plan is approved by the Regional Supervisor.
(6) The lessee shall review the MER for each producing sensitive reservoir at least once a year and submit Form MMS–127 with appropriate supporting information.
(7) The lessee may request the reclassification of a reservoir from sensitive to nonsensitive and request approval for termination of an MER by submitting Form MMS–127 with information supporting the reclassification and termination.
(8) At the request of the Regional Supervisor, the lessee shall furnish the information specified on Form MMS–127 for any producing nonsensitive reservoir.
(9) Public information copies of Form MMS–127 shall be submitted in accordance with §250.190.
(b) MPR. (1) The lessee shall propose an MPR for each producing well completion together with full information on the method used in its determination. The MPR shall be based on well tests and any limitations imposed by well and surface equipment, sand production, gas-oil and water-oil ratios, location of perforated intervals, and prudent operating practices. The sum of the MPR's of wells completed in a sensitive reservoir shall not exceed the approved MER.
(2) The lessee shall conduct a well-flow potential test within 30 days of the date of first continuous production on all new, recompleted, and reworked well completions. Within 15 days after the end of the test period, the lessee must submit a proposed MPR with well potential test for the individual well completion on Form MMS–126, Well Potential Test Report. The initial MPR shall not exceed 110 percent of the test rate submitted and shall be effective on the first day of the month following the end of the test period if approved by the Regional Supervisor. During the 30-day period allowed for testing, the lessee may produce a new, recompleted, or reworked completion at rates necessary to establish the MPR. After the 30-day period and prior to approval of the initial MPR, a well completion may be produced at a rate not to exceed the proposed rate. The lessee shall report the total production obtained during the test period and shall identify all other wells completed in the reservoir on Form MMS–126.
(3) At least one well test shall be conducted during a calendar half for producing oil-well and gas-well completions and results submitted on Form MMS–128, Semiannual Well Test Report. Well tests shall be submitted within 45 days of the day the test was conducted.
(4) Unless otherwise ordered by the Regional Supervisor, a revised MPR shall automatically be approved for each well completion for each well test submitted equal to 110 percent of the test rate. The revised MPR will be effective on the first day of the month following the date the well test was conducted. Prior to the approval of a proposed increase of the MPR, a well completion may be produced at a rate not to exceed the proposed increased rate.
(5) When a well test is not submitted during a calendar half for a producing oil-well or gas-well completion, the MPR will be automatically canceled effective on the first day of the appropriate following calendar half.
(6) When the results of a semiannual well test for an oil-well or gas-well completion cannot be submitted within the specified time, the lessee shall request an extension of time for submitting those test results. The extension must be approved in advance by the Regional Supervisor to continue production under the last approved MPR.
(7) When approved by the Regional Supervisor, an MPR shall not be exceeded, except as provided in paragraphs (b)(4) and (c) of this section.
(8) Public Information copies of Form MMS–126 shall be submitted in accordance with §250.190.
(9) Public information copies of Form MMS–128 shall be submitted in accordance with §250.190.
(c) Temporary rates. Temporary production rates resulting from normal variations and fluctuations exceeding a well MPR or reservoir MER shall not be considered a violation, provided that such production in excess of an approved MER is balanced by production in accordance with the provisions of paragraph (a)(5) of this section.
[53 FR 10690, Apr. 1, 1988, as amended at 58 FR 49928, Sept. 24, 1993. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 64 FR 72794, Dec. 28, 1999; 65 FR 2875, Jan. 19, 2000]
§ 250.1103 Well production testing.
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(a) The required well testing shall be conducted for a period of not less than four consecutive hours. Immediately prior to the 4-hour test period, the well completion shall have produced under stabilized conditions for a period of not less than six consecutive hours. The 6-hour pretest period shall not begin until after the recovery of a volume of fluid equivalent to the amount of fluids introduced into the formation during completion, recompletion, reworking, or treatment operations. Measured gas volumes shall be adjusted to the standard conditions of 14.73 pounds per square inch absolute (psia) (15.025 psia in the Gulf of Mexico OCS Region) and 60 °F for all tests. When orifice meters are used, a specific gravity for the gas shall be obtained or estimated, and a specific gravity-correction factor shall be applied to the orifice coefficient. The Regional Supervisor may require a prolonged test or retest of a well completion if the test is determined to be necessary for the establishment of a well MPR or a reservoir MER. The Regional Supervisor may approve test periods of less than 4 hours and pretest stabilization periods of less than 6 hours for well completions provided that test reliability can be demonstrated under such procedures.
(b) At the request of the Regional Supervisor, the lessee shall conduct a multipoint back-pressure test to determine the theoretical open-flow potential of a gas well. The test shall be conducted within 30 days of the Regional Supervisor's request or within the time period specified by the Regional Supervisor.
(c) An MMS representative may witness any well test of oil-well and gas-well completions. Upon request, a lessee shall provide advance notice to the Regional Supervisor of the time and date of well tests.
§ 250.1104 Bottomhole pressure survey.
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(a) For each new reservoir, the lessee shall conduct a static bottomhole pressure survey within 3 months after the date of first continuous production.
(b) For each producing reservoir with three or more producing completions, the lessee shall conduct annual static bottomhole pressure surveys in a sufficient number of key wells to establish an average reservoir pressure. The Regional Supervisor may require that a survey be performed on specific wells.
(c) The results of all static bottomhole pressure surveys obtained by the lessee shall be filed with the Regional Supervisor within 60 days after the date of the survey.
§ 250.1105 Flaring or venting gas and burning liquid hydrocarbons.
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(a) Lessees may flare or vent oil-well gas or gas-well gas without receiving prior approval from the Regional Supervisor only in the following situations:
(1) When gas vapors are flared or vented in small volumes from storage vessels or other low-pressure production vessels and cannot be economically recovered.
(2) During an equipment failure or to relieve system pressures. The lessee must comply with the following conditions:
(i) Lessees must not flare or vent oil-well gas for more than 48 continuous hours unless the Regional Supervisor approves. The Regional Supervisor may specify a limit of less than 48 hours to prevent air quality degradation.
(ii) Lessees must not flare or vent gas from a facility for more than 144 cumulative hours during any calendar month unless the Regional Supervisor approves.
(iii) Lessees must not flare or vent gas-well gas beyond the time required to eliminate an emergency unless the Regional Supervisor approves.
(3) During the unloading or cleaning of a well, drill-stem testing, production testing, or other well-evaluation testing. Flaring or venting must not exceed 48 cumulative hours per testing operation on a single completion. The Regional Supervisor may allow less time to prevent air quality degradation or more time if lessees need additional time to evaluate reservoir parameters.
(b) Lessees may flare or vent oil-well gas for up to 1 year when the Regional Supervisor approves the request for one of the following reasons:
(1) The lessee initiated an action which, when completed, will eliminate flaring and venting; or
(2) The lessee submitted an evaluation supported by engineering, geologic, and economic data indicating that either:
(i) The oil and gas produced from the well(s) will not economically support the facilities necessary to save and/or sell the gas; or
(ii) There is not enough gas to market.
(c) Lessees may burn produced liquid hydrocarbons only if the Regional Supervisor approves. To burn produced liquid hydrocarbons, the lessee must demonstrate that the amounts to burn would be minimal, or that the alternatives are infeasible or pose a significant risk that may harm offshore personnel or the environment. Alternatives to burning liquid hydrocarbons include transporting the liquids or storing and re-injecting them into a producible zone.
(d) Lessees must prepare records detailing gas flaring or venting and liquid hydrocarbon burning for each facility. The records must include, at a minimum:
(1) Daily volumes of gas flared or vented and liquid hydrocarbons burned;
(2) Number of hours of flaring, venting, or burning on a daily basis;
(3) Reasons for flaring, venting, or burning; and
(4) A list of the wells contributing to flaring, venting, or burning, along with the gas-oil ratio data.
(e) Lessees must keep these records for at least 2 years. Lessees must allow Minerals Management Service representatives to inspect the records at the lessees' field office that is nearest the Outer Continental Shelf facility, or at another location agreed to by the Regional Supervisor. If the Regional Supervisor requests to see the records, lessees must provide a copy.
(f) Requirements for flaring and venting of gas containing H2S—(1) Flaring of gas containing H2S. (i) The Regional Supervisor may, for safety or air pollution prevention purposes, further restrict the flaring of gas containing H2S. The Regional Supervisor will use information provided in the lessee's H2S Contingency Plan (§250.490(f)), Exploration Plan or Development and Production Plan, and associated documents in determining the need for such restrictions.
(ii) If the Regional Supervisor determines that flaring at a facility or group of facilities may significantly affect the air quality of an onshore area, the Regional Supervisor may require the operator(s) to conduct an air quality modeling analysis to determine the potential effect of facility emissions on onshore ambient concentrations of SO2. The Regional Supervisor may require monitoring and reporting or may restrict or prohibit flaring pursuant to §§250.303 and 250.304.
(2) Venting of gas containing H2S. You must not vent gas containing H2S except for minor releases during maintenance and repair activities that do not result in a 15-minute time weighted average atmospheric concentration of H2S of 20 ppm or higher anywhere on the platform.
(3) Reporting flared gas containing H2S. In addition to the recordkeeping requirements of paragraphs (d) and (e) of this section, when required by the Regional Supervisor, the operator must submit to the Regional Supervisor a monthly report of flared and vented gas containing H2S. The report must contain the following information:
(i) On a daily basis, the volume and duration of each flaring episode;
(ii) H2S concentration in the flared gas; and
(iii) Calculated amount of SO2 emitted.
[61 FR 25148, May 20, 1996, as amended at 62 FR 3800, Jan. 27, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 68 FR 8435, Feb. 20, 2003]
§ 250.1106 Downhole commingling.
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(a) An application to commingle hydrocarbons produced from multiple reservoirs within a common wellbore shall be submitted to the Regional Supervisor for approval and shall include all pertinent well information, geologic and reservoir engineering data, and a schematic diagram of well equipment. The application shall provide the estimated recoverable reserves as well as any available alternate drainage points which might be used to produce the reservoirs separately.
(b) For a competitive reservoir, notice of intent to submit the application shall be sent by the applicant to all other lessees having an interest in the reservoir prior to submitting the application to the Regional Supervisor.
(c) The application shall specify the well-completion number to be used for subsequent reporting purposes.
(d) The applicant must pay the service fee listed in §250.125 of this part with its request for downhole commingling.
[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, as amended at 70 FR 49876, Aug. 25, 2005]
§ 250.1107 Enhanced oil and gas recovery operations.
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(a) The lessee shall timely initiate enhanced oil and gas recovery operations for all competitive and noncompetitive reservoirs where such operations would result in an increased ultimate recovery of oil or gas under sound engineering and economic principles.
(b) A proposed plan for pressure maintenance, secondary and tertiary recovery, cycling, and similar recovery operations to increase the ultimate recovery of oil and/or gas from a reservoir shall be submitted to the Regional Supervisor for approval before such operations are initiated.
(c) Periodic reports of the volumes of oil, gas, or other substances injected, produced, or reproduced shall be submitted as required by the Regional Supervisor.
Subpart L—Oil and Gas Production Measurement, Surface Commingling, and Security
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Source: 63 FR 26370, May 12, 1998, unless otherwise noted. Redesignated at 63 FR 29479, May 29, 1998.
§ 250.1200 Question index table.
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The table in this section lists questions concerning Oil and Gas Production Measurement, Surface Commingling, and Security.
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Frequently asked questions CFR citation
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1. What are the requirements for § 250.1202(a)
measuring liquid hydrocarbons?.
2. What are the requirements for liquid § 250.1202(b)
hydrocarbon royalty meters?.
3. What are the requirements for run § 250.1202(c)
tickets?.
4. What are the requirements for liquid § 250.1202(d)
hydrocarbon royalty meter provings?.
5. What are the requirements for § 250.1202(e)
calibrating a master meter used in
royalty meter provings?.
6. What are the requirements for § 250.1202(f)
calibrating mechanical-displacement
provers and tank provers?.
7. What correction factors must a lessee § 250.1202(g)
use when proving meters with a mechanical
displacement prover, tank prover, or
master meter?............................
8. What are the requirements for § 250.1202(h)
establishing and applying operating meter
factors for liquid hydrocarbons?.........
9. Under what circumstances does a liquid § 250.1202(i)
hydrocarbon royalty meter need to be
taken out of service, and what must a
lessee do?...............................
10. How must a lessee correct gross liquid § 250.1202(j)
hydrocarbon volumes to standard
conditions?.
11. What are the requirements for liquid § 250.1202(k)
hydrocarbon allocation meters?.
12. What are the requirements for royalty § 250.1202(l)
and inventory tank facilities?.
13. To which meters do MMS requirements § 250.1203(a)
for gas measurement apply?.
14. What are the requirements for § 250.1203(b)
measuring gas?.
15. What are the requirements for gas § 250.1203(c)
meter calibrations?.
16. What must a lessee do if a gas meter § 250.1203(d)
is out of calibration or malfunctioning?.
17. What are the requirements when natural § 250.1203(e)
gas from a Federal lease is transferred
to a gas plant before royalty
determination?...........................
18. What are the requirements for § 250.1203(f)
measuring gas lost or used on a lease?.
19. What are the requirements for the § 250.1204(a)
surface commingling of production?.
20. What are the requirements for a § 250.1204(b)
periodic well test used for allocation?.
21. What are the requirements for site § 250.1205(a)
security?.
22. What are the requirements for using § 250.1205(b)
seals?.
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[63 FR 26370, May 12, 1998. Redesignated and amended at 63 FR 29479, 29487, May 29, 1998]
§ 250.1201 Definitions.
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Terms not defined in this section have the meanings given in the applicable chapter of the API MPMS, which is incorporated by reference in 30 CFR 250.198. Terms used in Subpart L have the following meaning:
Allocation meter—a meter used to determine the portion of hydrocarbons attributable to one or more platforms, leases, units, or wells, in relation to the total production from a royalty or allocation measurement point.
API MPMS—the American Petroleum Institute's Manual of Petroleum Measurement Standards, chapters 1, 20, and 21.
British Thermal Unit (Btu)—the amount of heat needed to raise the temperature of one pound of water from 59.5 degrees Fahrenheit (59.5 °F) to 60.5 degrees Fahrenheit (60.5 °F) at standard pressure base (14.73 pounds per square inch absolute (psia)).
Calibration—testing (verifying) and correcting, if necessary, a measuring device to industry accepted, manufacturer's recommended, or regulatory required standard of accuracy.
Compositional Analysis—separating mixtures into identifiable components expressed in mole percent.
Gas lost—gas that is neither sold nor used on the lease or unit nor used internally by the producer.
Gas processing plant—an installation that uses any process designed to remove elements or compounds (hydrocarbon and non-hydrocarbon) from gas, including absorption, adsorption, or refrigeration. Processing does not include treatment operations, including those necessary to put gas into marketable conditions such as natural pressure reduction, mechanical separation, heating, cooling, dehydration, desulphurization, and compression. The changing of pressures or temperatures in a reservoir is not processing.
Gas processing plant statement—a monthly statement showing the volume and quality of the inlet or field gas stream and the plant products recovered during the period, volume of plant fuel, flare and shrinkage, and the allocation of these volumes to the sources of the inlet stream.
Gas royalty meter malfunction—an error in any component of the gas measurement system which exceeds contractual tolerances.
Gas volume statement—a monthly statement showing gas measurement data, including the volume (Mcf) and quality (Btu) of natural gas which flowed through a meter.
Inventory tank—a tank in which liquid hydrocarbons are stored prior to royalty measurement. The measured volumes are used in the allocation process.
Liquid hydrocarbons (free liquids)—hydrocarbons which exist in liquid form at standard conditions after passing through separating facilities.
Malfunction factor—a liquid hydrocarbon royalty meter factor that differs from the previous meter factor by an amount greater than 0.0025.
Natural gas—a highly compressible, highly expandable mixture of hydrocarbons which occurs naturally in a gaseous form and passes a meter in vapor phase.
Operating meter—a royalty or allocation meter that is used for gas or liquid hydrocarbon measurement for any period during a calibration cycle.
Pressure base—the pressure at which gas volumes and quality are reported. The standard pressure base is 14.73 psia.
Prove—to determine (as in meter proving) the relationship between the volume passing through a meter at one set of conditions and the indicated volume at those same conditions.
Pipeline (retrograde) condensate—liquid hydrocarbons which drop out of the separated gas stream at any point in a pipeline during transmission to shore.
Royalty meter—a meter approved for the purpose of determining the volume of gas, oil, or other components removed, saved, or sold from a Federal lease.
Royalty tank—an approved tank in which liquid hydrocarbons are measured and upon which royalty volumes are based.
Run ticket—the invoice for liquid hydrocarbons measured at a royalty point.
Sales meter—a meter at which custody transfer takes place (not necessarily a royalty meter).
Seal—a device or approved method used to prevent tampering with royalty measurement components.
Standard conditions—atmospheric pressure of 14.73 pounds per square inch absolute (psia) and 60 °F.
Surface commingling—the surface mixing of production from two or more leases or units prior to measurement for royalty purposes.
Temperature base—the temperature at which gas and liquid hydrocarbon volumes and quality are reported. The standard temperature base is 60 °F.
You or your—the lessee or the operator or other lessees' representative engaged in operations in the Outer Continental Shelf (OCS).
[63 FR 26370, May 12, 1998. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 64 FR 72794, Dec. 28, 1999]
§ 250.1202 Liquid hydrocarbon measurement.
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(a) What are the requirements for measuring liquid hydrocarbons? You must:
(1) Submit a written application to, and obtain approval from, the Regional Supervisor before commencing liquid hydrocarbon production or making changes to previously approved measurement procedures;
(2) Use measurement equipment that will accurately measure the liquid hydrocarbons produced from a lease or unit;
(3) Use procedures and correction factors according to the applicable chapters of the API MPMS as incorporated by reference in 30 CFR 250.198, when obtaining net standard volume and associated measurement parameters; and
(4) When requested by the Regional Supervisor, provide the pipeline (retrograde) condensate volumes as allocated to the individual leases or units.
(b) What are the requirements for liquid hydrocarbon royalty meters? You must:
(1) Ensure that the royalty meter facilities include the following approved components (or other MMS-approved components) which must be compatible with their connected systems:
(i) A meter equipped with a nonreset totalizer;
(ii) A calibrated mechanical displacement (pipe) prover, master meter, or tank prover;
(iii) A proportional-to-flow sampling device pulsed by the meter output;
(iv) A temperature measurement or temperature compensation device; and
(v) A sediment and water monitor with a probe located upstream of the divert valve.
(2) Ensure that the royalty meter facilities accomplish the following:
(i) Prevent flow reversal through the meter;
(ii) Protect meters subjected to pressure pulsations or surges;
(iii) Prevent the meter from being subjected to shock pressures greater than the maximum working pressure; and
(iv) Prevent meter bypassing.
(3) Maintain royalty meter facilities to ensure the following:
(i) Meters operate within the gravity range specified by the manufacturer;
(ii) Meters operate within the manufacturer's specifications for maximum and minimum flow rate for linear accuracy; and
(iii) Meters are reproven when changes in metering conditions affect the meters' performance such as changes in pressure, temperature, density (water content), viscosity, pressure, and flow rate.
(4) Ensure that sampling devices conform to the following:
(i) The sampling point is in the flowstream immediately upstream or downstream of the meter or divert valve (in accordance with the API MPMS as incorporated by reference in 30 CFR 250.198);
(ii) The sample container is vapor-tight and includes a power mixing device to allow complete mixing of the sample before removal from the container; and
(iii) The sample probe is in the center half of the pipe diameter in a vertical run and is located at least three pipe diameters downstream of any pipe fitting within a region of turbulent flow. The sample probe can be located in a horizontal pipe if adequate stream conditioning such as power mixers or static mixers are installed upstream of the probe according to the manufacturer's instructions.
(c) What are the requirements for run tickets? You must:
(1) For royalty meters, ensure that the run tickets clearly identify all observed data, all correction factors not included in the meter factor, and the net standard volume.
(2) For royalty tanks, ensure that the run tickets clearly identify all observed data, all applicable correction factors, on/off seal numbers, and the net standard volume.
(3) Pull a run ticket at the beginning of the month and immediately after establishing the monthly meter factor or a malfunction meter factor.
(4) Send all run tickets for royalty meters and tanks to the Regional Supervisor within 15 days after the end of the month;
(d) What are the requirements for liquid hydrocarbon royalty meter provings? You must:
(1) Permit MMS representatives to witness provings;
(2) Ensure that the integrity of the prover calibration is traceable to test measures certified by the National Institute of Standards and Technology;
(3) Prove each operating royalty meter to determine the meter factor monthly, but the time between meter factor determinations must not exceed 42 days;
(4) Obtain approval from the Regional Supervisor before proving on a schedule other than monthly; and
(5) Submit copies of all meter proving reports for royalty meters to the Regional Supervisor monthly within 15 days after the end of the month.
(e) What are the requirements for calibrating a master meter used in royalty meter provings? You must:
(1) Calibrate the master meter to obtain a master meter factor before using it to determine operating meter factors;
(2) Use a fluid of similar gravity, viscosity, temperature, and flow rate as the liquid hydrocarbons that flow through the operating meter to calibrate the master meter;
(3) Calibrate the master meter monthly, but the time between calibrations must not exceed 42 days;
(4) Calibrate the master meter by recording runs until the results of two consecutive runs (if a tank prover is used) or five out of six consecutive runs (if a mechanical-displacement prover is used) produce meter factor differences of no greater than 0.0002. Lessees must use the average of the two (or the five) runs that produced acceptable results to compute the master meter factor;
(5) Install the master meter upstream of any back-pressure or reverse flow check valves associated with the operating meter. However, the master meter may be installed either upstream or downstream of the operating meter; and
(6) Keep a copy of the master meter calibration report at your field location for 2 years.
(f) What are the requirements for calibrating mechanical-displacement provers and tank provers? You must:
(1) Calibrate mechanical-displacement provers and tank provers at least once every 5 years according to the API MPMS as incorporated by reference in 30 CFR 250.101; and
(2) Submit a copy of each calibration report to the Regional Supervisor within 15 days after the calibration.
(g) What correction factors must I use when proving meters with a mechanical-displacement prover, tank prover, or master meter? Calculate the following correction factors using the API MPMS as referenced in 30 CFR 250.198:
(1) The change in prover volume due to the effect of temperature on steel (Cts);
(2) The change in prover volume due to the effect of pressure on steel (Cps);
(3) The change in liquid volume due to the effect of temperature on a liquid (Ctl); and
(4) The change in liquid volume due to the effect of pressure on a liquid (Cpl).
(h) What are the requirements for establishing and applying operating meter factors for liquid hydrocarbons? (1) If you use a mechanical-displacement prover, you must record proof runs until five out of six consecutive runs produce a difference between individual runs of no greater than .05 percent. You must use the average of the five accepted runs to compute the meter factor.
(2) If you use a master meter, you must record proof runs until three consecutive runs produce a total meter factor difference of no greater than 0.0005. The flow rate through the meters during the proving must be within 10 percent of the rate at which the line meter will operate. The final meter factor is determined by averaging the meter factors of the three runs;
(3) If you use a tank prover, you must record proof runs until two consecutive runs produce a meter factor difference of no greater than .0005. The final meter factor is determined by averaging the meter factors of the two runs; and
(4) You must apply operating meter factors forward starting with the date of the proving.
(i) Under what circumstances does a liquid hydrocarbon royalty meter need to be taken out of service, and what must I do? (1) If the difference between the meter factor and the previous factor exceeds 0.0025 it is a malfunction factor, and you must:
(i) Remove the meter from service and inspect it for damage or wear;
(ii) Adjust or repair the meter, and reprove it;
(iii) Apply the average of the malfunction factor and the previous factor to the production measured through the meter between the date of the previous factor and the date of the malfunction factor; and
(iv) Indicate that a meter malfunction occurred and show all appropriate remarks regarding subsequent repairs or adjustments on the proving report.
(2) If a meter fails to register production, you must:
(i) Remove the meter from service, repair and reprove it;
(ii) Apply the previous meter factor to the production run between the date of that factor and the date of the failure; and
(iii) Estimate and report unregistered production on the run ticket.
(3) If the results of a royalty meter proving exceed the run tolerance criteria and all measures excluding the adjustment or repair of the meter cannot bring results within tolerance, you must:
(i) Establish a factor using proving results made before any adjustment or repair of the meter; and
(ii) Treat the established factor like a malfunction factor (see paragraph (i)(1) of this section).
(j) How must I correct gross liquid hydrocarbon volumes to standard conditions? To correct gross liquid hydrocarbon volumes to standard conditions, you must: (continued)