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Proposed Rule

Oil and Gas and Sulphur Operations on the Outer Continental Shelf (OCS)-Oil and Gas Production Requirements

Action

Proposed Rule.

Summary

MMS proposes to amend the regulations regarding oil and natural gas production. This is a complete rewrite of these regulations, addressing issues such as production rates, burning oil, and venting and flaring natural gas. The proposed rule would eliminate most restrictions on production rates and clarify flaring and venting limits. The proposed rule was written using plain language, so it will be easier to read and understand.

Unified Agenda

Oil and Gas Production Rates

3 actions from March 6th, 2007 to April 19th, 2010

  • March 6th, 2007
  • June 4th, 2007
    • NPRM Comment Period End
  • April 19th, 2010
 

Table of Contents Back to Top

Tables Back to Top

DATES: Back to Top

Submit comments by June 4, 2007. MMS may not fully consider comments received after this date. Submit comments to the Office of Management and Budget on the information collection burden in this rule by April 5, 2007.

ADDRESSES: Back to Top

You may submit comments on the rulemaking by any of the following methods. Please use the Regulation Identifier Number (RIN) 1010-AD12 as an identifier in your message. See also Public Comment Procedures under Procedural Matters.

  • MMS's Public Connect on-line commenting system, https://ocsconnect.mms.gov. Follow the instructions on the Web site for submitting comments.
  • Federal eRulemaking Portal: http://www.regulations.gov. Follow the instructions on the Web site for submitting comments.
  • E-mail MMS at rules.comments@mms.gov. Use RIN 1010-AD12 in the subject line.
  • Fax: 703-787-1546. Identify with the RIN, 1010-AD12.
  • Mail or hand-carry comments to the Department of the Interior; Minerals Management Service; Attention: Rules Processing Team (RPT); 381 Elden Street, MS-4024; Herndon, Virginia 20170-4817. Please reference “Oil and Gas Production Requirements, 1010-AD12” in your comments and include your name and return address.
  • Send comments on the information collection in this rule to: Interior Desk Officer 1010-AD12, Office of Management and Budget; 202/395-6566 (facsimile); e-mail: oira_docket@omb.eop.gov.

FOR FURTHER INFORMATION CONTACT: Back to Top

Amy C. White, Regulations and Standards Branch, 703-787-1665.

SUPPLEMENTARY INFORMATION: Back to Top

This rule proposes to revise subpart K, Oil and Gas Production Rates, of 30 CFR 250. The new version of subpart K would represent a major change in the structure and readability of the regulation with some changes in the requirements. This revision would eliminate some requirements that are no longer necessary in today's industry and clarify other requirements. Some of these revisions are based on a Government Accountability Office (GAO) report on natural gas flaring and venting.

GAO Report Back to Top

In July 2004, the GAO issued a report on world-wide emissions from vented and flared natural gas titled, “Natural Gas Flaring and Venting—Opportunities to Improve Data and Reduce Emissions” (GAO-04-809). This report is available on the GAO Web site at: http://www.gao.gov/new.items/d04809.pdf. This report reviewed the flaring and venting data available, the extent of flaring and venting, their contributions to greenhouse gas emissions, and opportunities for the federal government to reduce flaring and venting. The report found that:

  • The amount of gas emitted through flaring and venting worldwide is small compared with global natural gas production and represents a small portion of greenhouse gas emissions.
  • Worldwide flaring and venting is estimated to contribute, respectively, about 4 percent of the total methane and about 1 percent of the total carbon dioxide emissions caused by human activity.
  • EIA [Energy Information Administration] estimates that the United States flares or vents about 0.4 percent of its production, representing only 3 percent of the world's total amount of natural gas flared and vented.
  • In the United States, there are well-developed natural gas markets and infrastructure to reduce the flaring and venting of associated natural gas.
  • Since 1990, the quantity of oil produced has increased, but because of various global reduction initiatives, the quantity of natural gas flared and vented has remained constant. Consequently, natural gas emissions as a percentage of oil production have decreased.
  • Since the impact of methane (venting) on the earth's atmosphere is about 23 times greater than that of carbon dioxide (flaring), a small change in the ratio of flaring to venting could cause a disproportionate change in the impact of emissions.

The report concluded that more accurate records on flaring and venting are needed to determine the amount of the resource that is lost and the volume of greenhouse gas emissions these practices contribute to the atmosphere each year. The GAO made two recommendations to the Secretary of the Interior: (1) “Consider the cost and benefit of requiring that companies flare the natural gas, whenever possible, when flaring or venting is necessary,” and (2) “consider the cost and benefit of requiring that companies use flaring and venting meters to improve oversight.” In addition, there was a recommendation to the Secretary of Energy to consider, “in consultation with EPA [Environmental Protection Agency], MMS, and BLM [Bureau of Land Management], how to best collect separate statistics on flaring and venting.”

In comments on the draft report, the Department of the Interior (DOI) concurred with the report's recommendations and agreed to assess the cost effectiveness of requiring the oil and gas industry to implement these changes. MMS conducted analyses to assess the costs and benefits of requiring flare/vent meters and also of requiring flaring instead of venting. The first analysis supported the recommendation to require meters provided that the facilities process more than 2,000 barrels of oil per day (BOPD). This requirement is included in the proposed rule.

The second analysis indicated that a regulatory change to require flaring instead of venting may be appropriate. However, the cost of implementing this requirement is significant, and input from potentially affected parties is necessary to establish a reasonable threshold. MMS plans to work directly with interested parties to determine the best approach in considering the GAO recommendation to require flaring instead of venting natural gas. We are soliciting comments on this issue in this proposed rule. We would like comments related to additional costs, environmental impacts, and conditions or situations where flaring may not be advisable. We are planning a workshop to discuss the issue. The workshop would be followed by appropriate rulemaking.

To improve data collection, as the GAO report suggested, MMS is proposing that operators report flaring and venting volumes to MMS separately. Currently, MMS only collects information on the total natural gas flared and vented. Operators do not need to differentiate between the two categories. In addition, MMS inspectors currently use infrared cameras to verify natural gas venting.

Proposed Rule Back to Top

Organization

The proposed rule would completely restructure subpart K. The new version is divided into shorter, easier-to-read sections. Each section focuses on one topic instead of the arrangement in the current version, which covers multiple topics in each section. For example, in the current edition of subpart K, the regulations regarding burning liquid hydrocarbons, as well as those governing flaring or venting natural gas, are in one section. In the proposed rule, these same requirements are in five sections, making it easier for an operator to find the information that applies to its particular situation. The numbering for subpart K would start at § 250.1150 instead of § 250.1100 to accommodate other planned rulemaking. The proposed structure is shown in the following table:

Current rule Proposed rule
§ 250.1100Definitions for production rates § 250.105Definitions.
§ 250.105Definitions.  
§ 250.1101General requirements and classification of reservoirs § 250.1150General reservoir production requirements. § 250.1154How do I determine if my reservoir is sensitive?
§ 250.1155What information must I submit for sensitive reservoirs?
§ 250.1156What steps must I take to receive approval to produce within 500 feet of a unit or lease line?
§ 250.1157How do I receive approval to produce gas from an oil reservoir with an associated gas cap?
§ 250.1102Oil and gas production rates Requirements for production rates are largely eliminated. Portions retained were combined with new information in “§ 250.1159 May the Regional Supervisor limit my well or reservoir production rates?”
§ 250.1103Well production testing § 250.1151How often must I conduct well production tests?
§ 250.1152How do I conduct well tests?
§ 250.1104Bottomhole pressure survey § 250.1153When must I conduct a static bottomhole pressure survey?
§ 250.1105Flaring or venting of gas and burning liquid hydrocarbons § 250.1160When may I flare or vent gas?§ 250.1161When may I flare or vent gas for extended periods of time? § 250.1162When may I burn produced liquid hydrocarbons?
§ 250.1163How must I measure gas flaring or venting and liquid hydrocarbon burning volumes and what records must I maintain?
§ 250.1164What are the requirements for flaring or venting gas containing H 2 S?
§ 250.1106Downhole commingling § 250.1158How do I receive approval to downhole commingle hydrocarbons?
§ 250.1107Enhanced oil and gas recovery operations § 250.1165What must I do for enhanced recovery operations?
New § 250.1159May the Regional Supervisor limit my well or reservoir production rates?
§ 250.1166What additional reporting is required for developments in the Alaska Region?
§ 250.1167What information must I submit for approvals?

The organization of the proposed rule reflects the actual sequence of events that occurs as wells are developed and the resources produced. The proposed rule is written in plain language to conform to the DOI's standards for rule writing. These changes include incorporating tables, using a question format for section headings, and using pronouns. These changes would make the rule easier to understand. Finally, a table at the end of the rule lists the information that operators would have to submit to MMS to receive approvals for various operations.

Major Changes to the Rule

Some requirements from the previous edition of subpart K would be eliminated by the proposed rule because they are unnecessary in today's petroleum industry. For example, MMS required operators to establish maximum production rates (MPR's) for producing well completions, and maximum efficient rates (MER's) for producing reservoirs, in OCS Order No. 11 in 1974, during a period of oil shortages and energy crises. In 1988, MMS reduced the MER requirement. Currently, MER's are required only on sensitive reservoirs (primarily oil reservoirs with associated gas caps). Determining and maintaining production rates imposes a significant burden on operators. Based on the past 30 years of experience, MMS has concluded that maximum rate requirements and production balancing requirements can be largely eliminated without significant detriment to efforts for conservation and maximization of ultimate recovery. However, the proposed rule would allow the Regional Supervisor to set production rates in cases where excessive production could harm ultimate recovery from the reservoir.

The proposed rule would clarify required information submittals to MMS, including requirements relating to the documents submitted to MMS and the timing of those submissions. For example, there is additional guidance on notifying adjoining operators regarding production within 500 feet of a common lease or unit line. The proposed rule would provide more detail as to when the notification must occur, what the notice must include, and how to verify the notification with MMS.

The proposed rule would incorporate several Notices to Lessees and Operators (NTLs) that clarify the current regulations. These NTLs would be obsolete if the proposed rule becomes final and MMS would withdraw all of these NTLs at that time. However, if necessary, MMS would issue additional NTLs to provide guidance. The NTLs affected include:

  • NTL No. 97-16, “Production Within 500 Feet of a Unit or Lease Line,” effective August 1, 1997. This NTL clarifies MMS policy on issuing approvals for production within 500 feet of a unit or lease line, and includes details on what the requesting operator needs to provide to MMS for approval. Those details are addressed in the proposed rule.
  • NTL No. 98-23, “Interim Reporting Requirements for 30 CFR 250, subpart K, Oil and Gas Production Rates,” effective October 15, 1998. This NTL addressed oral approvals for gas flaring and relaxed some of the requirements regarding production rates, including MER and MPR in certain circumstances. The NTL clarified the submittal of written summary letters on flaring incidents that received oral approval. These requirements are addressed in the proposed rule.
  • NTL No. 99-G20, “Downhole Commingling Applications,” effective September 7, 1999. This NTL was issued in conjunction with NTL No. 99-G19. It clarifies what information the applicant needs to include in downhole commingling applications to ensure that the application is processed without delay. These information requirements were added to the proposed rule.
  • NTL No. 2006-N06, “Flaring and Venting Approvals,” effective December 19, 2006. This NTL clarifies the definitions of flaring and venting, the record-keeping requirements, the classification of emitted natural gas, and the MMS policy regarding continuous flaring or venting of small volumes of oil-well gas or gas-well gas from storage vessels or other low-pressure production vessels when the gas cannot be economically recovered. These issues are addressed in the proposed rule. This NTL also provides contact information for each Region and provides sample field records. These two items are not addressed in the proposed rule. MMS would issue a new NTL to include only this information, after we publish the final rule.

The most significant change, with regard to cost, would be a proposed requirement for natural gas flare/vent meters on facilities that process significant volumes of oil. The current MMS requirements rely heavily on the accuracy of operator calculations and record keeping. Recent incidents have shown that these methods are insufficient to accurately capture actual flaring and venting volumes. The proposed rule would require the installation of meters to accurately measure all flared and vented natural gas on facilities that process more than 2,000 BOPD. These facilities have the potential to flare or vent significant volumes of associated gas.

MMS estimates the cost of purchasing and installing these meters to be $77,000 per facility. Limiting the requirement to facilities that process over 2,000 BOPD ensures that the meters are a small expense relative to the cost of operating those facilities and relative to the income generated by those facilities; and that the requirement would not be an unfair burden to small operators. MMS estimates that 34 operators would have to install the meters on 112 facilities. Of those operators that would have to install the meters, nine are considered small businesses, according to the North American Industry Classification System (NAICS).

The July 2004 GAO report on world-wide emissions from vented and flared natural gas, discussed above, recommended that more accurate records on flaring and venting are needed to determine the amount of the resource that is wasted, and the volume of greenhouse gas these practices contribute to the atmosphere each year. The report recommended that DOI consider requiring flare/vent meters to measure the gas lost. MMS agrees with that recommendation. However, MMS believes installing these meters on facilities that process less than 2,000 BOPD would not be cost effective, and might be an undue burden on smaller operators.

MMS is also proposing to add new definitions for “flaring” and “venting” to 30 CFR part 250 subpart A, and to revise the definition for “sensitive reservoir.”

The following is a brief section-by-section description of the substantive proposed changes to subpart K:

§ 250.105Definitions. In the current rule, definitions appear in subpart A at 30 CFR 250.105 and in subpart K at 30 CFR 250.1100. MMS proposes removing the definitions from subpart K because they already appear in subpart A.

General

§ 250.1150What are General Reservoir Production Requirements? Because the first section of subpart K would no longer contain the definitions, this section would contain the general requirements for producing wells and reservoirs.

Well Tests and Surveys

§ 250.1151How often must I conduct well production tests? Well production testing is required for all wells. This proposed section defines when an operator must perform the tests and describes the conditions for the tests. This section would cover well flow potential tests, semi-annual well tests, and any special tests that the Regional Supervisor may require. Operators would no longer be required to submit Semiannual Well Test Reports within 45 days of the tests. Instead, they would submit the reports within 45 days after the end of the calendar half-year. This would allow operators to submit all their well tests at one time and include the most recent tests for those few completions that produced during the 6-month period, but were not tested within the last 45 days.

§ 250.1152How do I conduct well tests? This proposed section describes how operators must conduct a well test. The testing procedures would be the same as in the current version of the rule. However, the section would be reformatted to make the procedures easier to follow. This reformatting would include the procedure for ensuring that the well is stabilized before conducting the test; the required duration of the test; the usage of correction factors and adjustments; and an option to use other procedures with approval from the Regional Supervisor. It also discusses conducting additional tests that the Regional Supervisor may require.

§ 250.1153When must I conduct a static bottomhole pressure survey? Static bottomhole pressure surveys are required on all new producing reservoirs, and annually on reservoirs with three or more producing completions. This proposed section addresses when operators must conduct static bottomhole pressure surveys and what information operators must submit to MMS. The proposed new provision would allow the operator to request a departure from this requirement from the Regional Supervisor, with appropriate justification.

Classifying Reservoirs

§ 250.1154How do I determine if my reservoir is sensitive? MMS requires that operators classify all reservoirs as either sensitive or non-sensitive. A sensitive reservoir is a reservoir in which high reservoir production rates would decrease ultimate recovery. This section would define the requirements for classifying reservoirs; when the Regional Supervisor may reclassify a reservoir; and when an operator may or must request reclassification of a reservoir. There are not substantive changes between the requirements of the current version of the rule and the proposed; this section would be reorganized and easier to read.

§ 250.1155What information must I submit for sensitive reservoirs? This proposed section defines what information MMS requires for sensitive reservoirs and when operators must submit that information. The only proposed change is that the Regional Supervisor may request that the operator submit Form MMS-127 (Sensitive Reservoir Information Report) and supporting information.

Approvals Prior to Production

§ 250.1156What steps must I take to receive approval to produce within 500 feet of a unit or lease line? In the current version of subpart K, a number of requirements, including approval for producing within 500 feet of a unit or lease line and basic classification requirements, are included in one section, 30 CFR 250.1101. In the proposed rule, each of these issues is addressed in a separate section. Title 30 CFR 250.1156 would address only the approval and service fee for producing within 500 feet of a lease or unit line.

The proposed approval requirements are clearer than in the current rule, and include issues addressed in NTL 97-16. In addition to receiving approval from the Regional Supervisor, operators must notify operators of adjacent leases. The requirement to notify adjacent operators would be clearer, and there is a list of information the notification would have to include.

§ 250.1157How do I receive approval to produce gas from an oil reservoir with an associated gas cap? This section would address how to receive approval to produce from an associated gas cap and its service fee. The required supporting information is listed in the table at proposed 30 CFR 250.1167 at the end of the rule.

§ 250.1158How do I receive approval to downhole commingle hydrocarbons? This section would address how to obtain MMS approval to downhole commingle hydrocarbons and the service fee that must accompany your request. For downhole commingling in a competitive reservoir, the operator would be required to notify the operators of all leases that contain the reservoir. The request for approval must document this notification. Operators of the other leases would have 30 days after the notification to provide the Regional Supervisor with letters of acceptance or objection. If the notified operators do not respond within the specified period, the Regional Supervisor will assume the operators do not object. The Regional Supervisor will consider any objections, but may approve the commingling request to protect correlative rights. This section would also incorporate issues addressed in NTL's No. 99-G19 and 99-G20.

Production Rates

§ 250.1159May the Regional Supervisor limit my well or reservoir production rates? Generally, this proposed rule would eliminate MPR's and MER's. However, this section would retain the Regional Supervisor's authority to set an MPR for a producing well completion or an MER for a sensitive reservoir. If the Regional Supervisor sets an MPR or MER, it would be subject to the terms and conditions set by the Regional Supervisor. Those terms and conditions would include production restrictions that allow for normal variations and fluctuations in production rates.

Flaring, Venting, and Burning Hydrocarbons

§ 250.1160When may I flare or vent gas? The current regulation contains all of the flaring, venting, and burning regulations in one section. The proposed rule covers these in separate sections, so it is easier to find the requirements for a given situation. The new format also allows for the inclusion of more detail and clarification of flaring and venting situations that are not described in the current rule. Since there are many situations under which flaring and venting might occur, the table in this section reflects general categories that encompass the situations under which MMS would allow flaring or venting without approval from the Regional Supervisor. Under most circumstances, the proposed rule would allow operators to treat gas flashing from gas-well condensate similar to oil-well gas for flaring and venting approval purposes.

The proposed rule would require operators to receive approval before flaring or venting gas in volumes higher than those specified in their previously-approved plans. This would enable MMS to ensure that flaring and venting activities are in compliance with environmental laws.

The proposed rule would also allow the Regional Supervisor to specify flaring and venting volume limits (in addition to time limits) in order to prevent air quality degradation or the loss of reserves. This is sometimes necessary because offshore production facilities are now capable of flaring or venting extremely large volumes in a short amount of time.

§ 250.1161When may I flare or vent gas for extended periods of time? This section would define when operators must receive approval from the Regional Supervisor to flare or vent gas for an extended period of time. If there is a need to flare or vent a small amount of gas (less than 10 MCF per day) due to improperly working valves or pipe fittings and the Regional Supervisor determines that it is prudent to postpone the repair until a scheduled facility shutdown occurs, then the proposed rule would allow the Regional Supervisor to exempt the amount flared or vented from the time limits set in § 250.1160.

§ 250.1162When may I burn produced liquid hydrocarbons? The regulations on burning produced liquid hydrocarbon would not change. Operators must receive approval from the Regional Supervisor in all cases before burning liquid hydrocarbons.

§ 250.1163How must I measure gas flaring or venting volumes, and liquid hydrocarbon burning volumes; and what records must I maintain? Requirements for measuring and keeping records on flaring, venting, and burning would change. The proposed rule would require vent/flare meters on all facilities that process more than 2,000 BOPD. Operators would be required to install these meters within 120 days after the final rule is published. This extended time frame is to accommodate operators that are required to install meters at multiple facilities. Facilities that do not process more than 2,000 BOPD when the final rule is published, but increase production above this level after the rule is published, would be required to install meters within 90 days.

Operators would be required to keep records on flaring, venting, and burning for 6 years to comply with 30 CFR Part 212—Records and Files Maintenance. The operators would be required to store these records on the facility for the first 2 years after the flaring, venting, or burning event. After that, the operator would be able to keep the records at a separate location, but they must be available for MMS review.

The proposed rule would clarify reporting procedures and require operators to report flared and vented volumes separately. The previously discussed GAO report concluded that MMS should collect flared and vented volumes separately. MMS tentatively agrees with this conclusion, and does not believe it will pose a significant burden on operators because they already report the volumes of gas flared and vented to MMS on Form MMS-4054 (Oil and Gas Operations Report). Operators would only need to identify whether the gas volumes were flared or vented.

The proposed rule would require operators to identify the facilities where the gas is flared or vented. This would enable MMS to directly compare volumes reported on Forms MMS-4054 with field records. This requirement would also reduce the burden on operators during royalty audits because operators would no longer have to reconstruct historical flare/vent allocations for MMS auditors.

The proposed rule would require operators to retain meter recordings on facilities that require flare/vent meters. This would allow MMS to compare eyewitness observations with field records and ensure that flaring and venting incidents are properly recorded. MMS does not believe this would be a significant burden on those facilities with flare/vent meters because these meters typically record such events automatically and operators usually maintain these electronic records for their own purposes.

In addition, the proposed rule would clarify when royalties are due on flared gas, vented gas, and burned liquid hydrocarbons under 30 CFR 202.100 Royalty on Oil and 30 CFR 202.150 Royalty on Gas. As in the current rule, royalties would not be due if the hydrocarbons were unavoidably lost. In most cases, MMS will consider hydrocarbons that are flared, vented or burned with MMS approval as “unavoidably lost” and the operator would not be required to pay royalties. However, MMS would retain the authority to determine whether or not the loss was avoidable or due to negligence, even if approved by MMS. For example, if you received MMS approval to flare 100 MCF of gas per day, then actually flared 100,000 MCF of gas per day under conditions that would not have been approved, MMS might determine that the entire volume flared was “avoidably lost” and royalties would be due on the entire volume. MMS would also be able to pursue civil penalties, under 30 CFR 250 subpart N—Outer Continental Shelf (OCS) Civil Penalties, if we determine that the loss was avoidable or due to negligence.

§ 250.1164What are the requirements for flaring or venting gas containing H 2 S? The proposed rule would require Regional Supervisor approval before emitting more than 15 lbs of SO 2 per hour per mile from shore. This would ensure that flaring activities are in compliance with environmental laws. MMS does not believe this would create an excessive burden on operators. The proposed regulations specify the records that the operator would have to keep. These records must be kept for 6 years, meeting the same requirements as in the previous section.

Enhanced Recovery

§ 250.1165What must I do for enhanced recovery operations? There are no significant proposed changes to the regulations regarding enhanced recovery operations. Operators would still be required to initiate enhanced recovery operations; receive Regional Supervisor approval for the plans; and submit reports on the substances injected, produced, or reproduced.

Special Alaska OCS Region Requirements

§ 250.1166What additional reporting is required for developments in the Alaska Region? This new section addresses special proposed reporting requirements for Alaska. This would require operators to submit an annual reservoir management report to the Regional Supervisor for any development in Alaska. If a development is regulated by both the MMS and the State of Alaska, the operator would be able to coordinate reporting requirements with MMS and the State of Alaska Oil and Gas Conservation Commission. This section would also require operators to request an MER for sensitive reservoirs in Alaska.

This is necessary for the MMS Alaska Region to administer Section 7 Agreements between the Secretary of the Interior and the Governor of the State of Alaska. Under existing Section 7 Agreements, oil and gas reserves underlying a common geologic structure must be unitized and the allocation of production between Federal and State leases for royalty payment must be based on recoverable oil and gas. Under agreement with the State, this determination will be based on reservoir performance following completion of the development drilling program and sustained production. Annual reservoir management plans enable the MMS to monitor recoverable oil and assure proper allocation of reserves for royalty payment and to be consistent with the State of Alaska requirements.

This provision would also enable the MMS to manage its responsibility for conservation of resources on a real time basis. The number, type, spacing and sequencing of development wells (producers and injectors) will vary from the original approved development and production plan as more information on the reservoir is obtained. An annual reservoir management plan would enable the MMS to track development activities with the approved development and production plan and assure maximum recovery based on the most current knowledge of the reservoir.

Information Needed With Forms and for Approvals

§ 250.1167What information must I submit with forms and for approvals? This proposed table is designed to be an easy-to-use reference to determine the information and supporting documentation to submit to the Regional Supervisor and to remind lessees to pay the appropriate service fee. Forms MMS-126 (Well Potential Test Report) and MMS-127 (Sensitive Reservoir Information Report) would require supporting documents. Also, several operations covered under subpart K (gas cap production, downhole commingling, reservoir reclassification, and production within 500 feet of a unit or lease line), would require that the operator submit applications and supporting documents to the Regional Supervisor. All of these documents are covered in the table.

Questions Back to Top

In addition to comments on these proposed regulations, MMS is requesting comments on the following questions.

1. Are these regulations well organized and easy to read?

2. Is the submittal table useful?

3. Is the 2,000 BOPD requirement for installing flare/vent meters reasonable? Are the cost estimates accurate?

4. Would the requirement to install flare/vent meters pose a safety hazard by restricting flow during emergency facility blowdowns, or are accurate meters (such as ultrasonic meters) available that do not impede gas flow?

5. Should MMS require operators to flare natural gas instead of venting it, under approved flaring and venting conditions? This question is based on a recommendation from the GAO report on flaring and venting natural gas, and reflects concerns about the amount of greenhouse gas that is released into the environment by venting. MMS is studying this recommendation before proposing any regulatory change. We would like comments on this issue, including comments related to additional costs, environmental impacts, and conditions or situations where flaring may not be advisable.

Procedural Matters Back to Top

Public Availability of Comments

Before including your address, phone number, e-mail address, or other personal identifying information in your comment, you should be aware that your entire comment—including your personal identifying information—may be made publicly available at any time. While you can ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.

Regulatory Planning and Review (Executive Order (E.O.) 12866)

This proposed rule is not a significant rule as determined by the Office of Management and Budget (OMB) and is not subject to review under E.O. 12866.

(1) The proposed rule would not have an annual economic effect of $100 million or more on the economy. It would not adversely affect in a material way the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or tribal governments or communities. A cost-benefit and economic analysis is not required.

This proposed rule revises the requirements for oil and gas production. The changes in the rule are not significant enough to have an impact on the economy or an economic sector, productivity, jobs, the environment, or other units of government. Some of the current requirements would be relaxed. For example, limits on production rates were eliminated in most cases. This would allow the operators to produce the oil and gas at the rates that they determine are best, and would not have a significant effect on any sector of the economy.

(2) The proposed rule would not create a serious inconsistency or otherwise interfere with action taken or planned by another agency because MMS is the only Federal government agency directly involved in setting production requirements for the offshore oil and natural gas industry.

(3) This proposed rule would not alter the budgetary effects of entitlements, grants, user fees or loan programs, or the rights and obligations of their recipients.

(4) This proposed rule would not raise novel legal or policy issues. There are some changes in production requirements in this proposal, but most of the changes clarify existing MMS requirements. Some may require additional paperwork for the operators. Since the basic production requirements are not changed, and restrictions on production rates are decreased, this proposed rule should not raise novel legal or policy issues.

Regulatory Flexibility Act (RFA)

The Department of the Interior certifies that this proposed rule would not have a significant economic effect on a substantial number of small entities as defined under the RFA (5 U.S.C. 601 et seq.). An initial Regulatory Flexibility Analysis is not required. Accordingly, a Small Entity Compliance Guide is not required.

This rule applies to all lessees operating on the OCS. Lessees fall under the Small Business Administration's North American Industry Classification System (NAICS) code 211111, Crude Petroleum and Natural Gas Extraction. Under this NAICS code, companies with less than 500 employees are considered small businesses. MMS estimates that 130 lessees explore for and produce oil and gas on the OCS; approximately 70 percent of them (91 companies) fall into the small business category. The proposed regulation would therefore affect a substantial number of small entities. However, we have determined that it would not have a significant economic effect on these small entities.

One new requirement that would impose a cost to operators is a requirement to install flaring/venting meters on all facilities that process more than 2,000 BOPD. The GAO report on flaring and venting natural gas, released in July 2004, recommended that MMS require these meters to improve oversight. MMS agrees with this recommendation. MMS regulations allow flaring and venting in very limited circumstances. These meters would help MMS:

  • Verify the amounts of natural gas that operators flare or vent into the environment;
  • Prevent waste of resources;
  • Collect the proper royalties on avoidably flared or vented gas;
  • Determine if an operator is violating MMS regulations; and
  • Assess the impacts on the environment.

In determining the criteria for which facilities must install the meters, MMS considered the cost of the meters and the amount of production needed to justify the cost. To ensure that the requirement to install flare/vent meters would not produce an undue burden on small companies, it was limited to those facilities that process more than an average of 2,000 BOPD.

MMS estimates that 34 companies would have to install meters on 112 facilities at an average cost of $77,000 per facility and a total cost to industry of $8,624,000 (112 × $77,000 = $8,624,000). Of those, nine companies are considered small businesses, based on the NAICS. These nine companies represent only 7 percent of the 130 operators on the OCS. We estimate that seven of these nine companies would need to install meters on one facility each; one company would need to install meters on two facilities; and one company would need to install meters on three facilities. This represents an average cost of $105,875 for each of the small companies (11 facilities × $77,000/9 companies). The average cost to non small companies would be $311,080 per company (101 facilities × $77,000/25 companies). In addition, this does not represent an unfair burden to small companies because the cost of these meters is small in comparison to the revenues generated by the amount of oil processed by those facilities.

Your comments are important. The Small Business and Agriculture Regulatory Enforcement Ombudsman and 10 Regional Fairness Boards were established to receive comments from small businesses about Federal agency enforcement actions. The Ombudsman will annually evaluate the enforcement activities and rate each agency's responsiveness to small business. If you wish to comment on the actions of MMS, call 1-888-734-3247. You may comment to the Small Business Administration without fear of retaliation. Disciplinary action for retaliation by an MMS employee may include suspension or termination from employment with the DOI.

Small Business Regulatory Enforcement Fairness Act (SBREFA)

The proposed rule is not a major rule under SBREFA (5 U.S.C. 804(2)). This proposed rule:

a. Would not have an annual effect on the economy of $100 million or more. This proposed rule revises the requirements for oil and gas production. The changes would not have an impact on the economy or an economic sector, productivity, jobs, the environment, or other units of government. Most of the new requirements are paperwork requirements, and would not add significant time to development and production processes. One new requirement would add new costs for some operators. Operators would be required to install flare/vent meters on any facility that processes more than an average of 2,000 BOPD. MMS estimates that 34 companies would have to install meters on 112 facilities at an average cost of $77,000 per facility and a total cost to industry of $8,624,000 (112 × $77,000 = $8,624,000).

b. Would not cause a major increase in costs or prices for consumers, individual industries, Federal, State, or local government agencies, or geographic regions.

In most cases, this proposed rule would eliminate the requirement for operators to set limits on production rates, allowing the operators to determine the best rate to produce their reservoirs. The limits on burning, flaring, and venting are clearer. These limits would encourage conservation of our natural resources, without putting undue production restrictions on operators. There would be a new requirement to install meters on facilities that process more than an average of 2,000 BOPD. As discussed above, this requirement would not significantly increase the cost of doing business offshore.

c. Would not have significant adverse effects on competition, employment, investment, productivity, innovation, or the ability of U.S.-based enterprises to compete with foreign-based enterprises. This proposed rule would eliminate the requirement for operators to set limits on production rates, allowing the operators to determine the best rate to produce their reservoirs. There are clearer limits on burning, flaring, and venting, which would encourage conservation of our natural resources.

Unfunded Mandates Reform Act (UMRA) of 1995

This proposed rule would not impose an unfunded mandate on State, local, or tribal governments or the private sector of more than $100 million per year. The proposed rule would not have a significant or unique effect on State, local, or tribal governments or the private sector. A statement containing the information required by UMRA (2 U.S.C. 1531 et seq.) is not required. This is because the proposal would not affect State, local, or tribal governments, and the effect on the private sector is small.

Takings Implication Assessment (Executive Order 12630)

The proposed rule is not a governmental action capable of interference with constitutionally protected property rights. Thus, MMS did not need to prepare a Takings Implication Assessment according to E.O. 12630, Governmental Actions and Interference with Constitutionally Protected Property Rights.

Federalism (Executive Order 13132)

With respect to E.O. 13132, this proposed rule would not have federalism implications. This proposed rule would not substantially and directly affect the relationship between the Federal and State governments. To the extent that State and local governments have a role in OCS activities, this proposed rule would not affect that role.

MMS has the authority to regulate offshore oil and gas production. State governments do not have authority over offshore production in Federal waters.

Civil Justice Reform (Executive Order 12988)

With respect to E.O. 12988, the Office of the Solicitor has determined that the proposed rule would not unduly burden the judicial system and does not meet the requirements of sections 3(a) and 3(b)(2) of the Order. MMS drafted this proposed rule in plain language to provide clear standards. We consulted with the Department of the Interior's Office of the Solicitor throughout the drafting process for the same reasons.

Paperwork Reduction Act (PRA) Back to Top

The proposed rule contains a collection of information that has been submitted to OMB for review and approval under § 3507(d) of the PRA. As part of our continuing effort to reduce paperwork and respondent burdens, MMS invites the public and other Federal agencies to comment on any aspect of the reporting and recordkeeping burden. You may submit your comments on the information collection aspects of this proposed rule directly to the Office of Management and Budget (OMB), Office of Information and Regulatory Affairs, OMB Attention: Desk Officer for the Department of the Interior via OMB e-mail: (OIRA_DOCKET@omb.eop.gov); or by fax (202) 395-6566; identify with 1010-AD12. Send a copy of your comments to the Rules Processing Team (RPT), Attn: Rules Comments; 381 Elden Street, MS-4024; Herndon, Virginia 20170-4817. Please reference “Oil and Gas Production Requirements—AD12” in your comments. You may obtain a copy of the supporting statement for the new collection of information by contacting the Bureau's Information Collection Clearance Officer at (202) 208-7744.

The PRA provides that an agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. OMB is required to make a decision concerning the collection of information contained in these proposed regulations 30-60 days after publication of this document in the Federal Register. Therefore, a comment to OMB is best assured of having its full effect if OMB receives it by April 5, 2007. This does not affect the deadline for the public to comment to MMS on the proposed regulations.

The title of the collection of information for the rule is “30 CFR 250, Subpart K, Oil and Gas Production Requirements.” The proposed regulations concern oil and gas production requirements, and the information is used in our efforts to conserve natural resources, prevent waste, and protect correlative rights, including the government's royalty interest.

Respondents are the approximately 130 Federal oil and gas and sulphur lessees. Responses to this collection are mandatory. The frequency of response is on occasion, monthly, semi-annually, annually, and as a result of situations encountered depending upon the requirement. The information collection (IC) does not include questions of a sensitive nature. MMS will protect proprietary information according to the Freedom of Information Act (5 U.S.C. 552) and its implementing regulations (43 CFR part 2), and 30 CFR 250.196, “Data and information to be made available to the public,” and 30 CFR part 252, “OCS Oil and Gas Information Program.” Proprietary information concerning geological and geophysical data will be protected according to 43 U.S.C. 1352.

The collection of information required by the current subpart K regulations is approved under OMB Control Number 1010-0041. The proposed rule imposes minor changes to the information collection burden. The changes are:

  • Report to Minerals Revenue Management (MRM) measured gas flaring or venting and liquid hydrocarbon burning. Submit periodic reports of volumes of oil, gas, or other substances injected, produced, or produced for a second time. Both requirements and burdens are now reported to MRM and their respective burdens are covered under OMB Control Number 1010-0139 (-154 burden hours);
  • Request Regional Supervisor approval for emitting more than 15 lbs. of SO 2 (+10 burden hours);
  • Submit to Regional Supervisor air quality modeling analysis report. The proposed burden hours represent an adjustment to a current requirement for information that was not previously collected (+40 burden hours);
  • For Alaska Region Only: Submit to Regional Supervisor annual reservoir management report and supporting information. (At this time, the state requires the same information and MMS receives a copy). Alaska has started producing in state waters. If new development occurs in Federal waters, a minimal burden for submitting an annual reservoir management report, and burden hours for annual revisions are being added (+161 burden hours).
  • Maintain meter records for detailing gas flaring or venting, and liquid hydrocarbon burning for 6 years. These new burden requirements do not add additional burden hours.
  • General departure or alternative compliance requests (+5 burden hours).

The currently approved information collection for this subpart (1010-0041) will be superseded by this collection when final regulations take effect.

Currently, regulations covered under OMB Control Number 1010-0041 have 43,065 annual burden hours. MMS estimates the total annual reporting and recordkeeping “hour” burden for the proposed rule to be 43,127 hours; this is an increase of 62 burden hours. With the exception of the recordkeeping requirement changes and the items identified as “new” in the following chart, the burden estimates shown are those that are estimated for the current subpart K regulations.

30 CFR 250 Subpart K Reporting recordkeeping requirement Fee/non-hour cost
Hour burden Average number of annual responses Annual burden hours
* Reporting burden for this form is estimated to average 0.1 to 3 hours per form depending on the number of well tests reported, including the time for reviewing instructions, gathering and maintaining data, and completing and reviewing the form. See breakdown for form MMS-128 above.
1151(a), (c); 1155; 1165; 1166(c); 1167 Submit form MMS-126 and supporting information 3 1,325 forms 3,975
Submit form MMS-127 and supporting information 2.2 2,189 forms 4,816
Submit form MMS-128 and supporting information 0.1—3 13,000 GOM forms 600 POCS forms 1,336*
1151(b) Request extension of time to submit results of semiannual well test 0.5 37 requests 19
1152(b), (c) Obtain Regional Supervisor approval to conduct well testing using alternative procedures; conduct tests/retests to establish proper MPR or MER; conduct multipoint backpressure test for open flow potential 0.5 37 requests 19
1152(d) Provide advance notice of time and date of well tests 0.5 10 notices 5
1153 Submit results of all static bottomhole pressure surveys obtained by lessee using form MMS-140. Request departure requirement w/justification to Regional Supervisor; submit with Form MMS-140 and supporting information 14 1 1,270 surveys 120 survey waivers 17,780 120
1154; 1167 Request reclassification of reservoir for Regional Supervisor approval and submit supporting information 6 20 requests 120
1156; 1167 Request approval to produce within 500 feet of a unit or lease line and submit supporting information; notify operators; provide proof of date to Regional Supervisor 5 50 requests 250
3,300 × 50 requests = $165,000
1157; 1167 Request approval to produce gas cap of a sensitive reservoir and submit supporting information; obtain approval to produce gas from an oil reservoir with an associated gas cap 12 125 requests 1,500
$4,200 × 125 requests = $525,000
1158; 1167 Submit request to downhole commingle hydrocarbons and supporting information; notify operators; provide proof of date to Regional Supervisor 6 119 applications 714
$4,900 × 119 applications = $583,100
1160; 1161 Request Regional Supervisor approval/inform to flare or vent oil-well gas or gas-well gas/exceed volume; submit documentation 0.5 1,007 requests 504
1162; 1163(e) Request approval to burn produced liquid hydrocarbons; submit documentation 0.5 60 requests 30
NEW 1163 Initial purchase and install gas meters to measure the amount of gas flared or vented. This is a non-hour cost burden 0 112 0
112 meters @ $77,000 ea = $8,624,000
NEW 1163(b); 1165(c) Report to MRM measured gas flaring or venting and liquid hydrocarbon burning—burden coveredunder 1010-0139 0
NEW 1164(b)(1) Request Regional Supervisor approval for emitting more than 15 lbs. of SO 2 0.5 20 requests 10
1164(b)(2) H 2 S Contingency, Exploration, or Development and Production Plans—burden covered under1010-0141 and 1010-0151 0
NEW 1164(b)(3) Submit to Regional Supervisor air quality modeling analysis 40 1 modeling analysis 40
1164(c) Submit monthly reports of flared or vented gas containing H 2 S 2 3 operators × 12 mos. = 36 72
1165 Submit proposed plan for enhanced recovery operations 12 27 plans 324
1165(c) Submit periodic reports of volumes of oil, gas, or other substances injected, produced, or produced for a second time—burden covered under OMB approval 1010-0139 0
NEW 1166 Alaska Region only: submit to Regional Supervisor annual reservoir management report and supporting information 1 100 1 (required by State, MMS gets copy) 1 new develop not State lands 1 100
20 3 annual revisions 60
NEW 1150-1167 General departure or alternative compliance requests not specifically covered elsewhere in subpart K 1 5 5
Reporting Subtotal 20,175 31,800    
1163(c), (d) Maintain records for 6 years detailing gas flaring or venting; maintain meter records and provide copies if requested 13 869 platforms 11,297
1163(c) Maintain records for 6 years detailing liquid hydrocarbon burning; maintain meter records and provide copies if requested 0.5 60 occurrences 30
Recordkeeping Subtotal 929 11,327    
Total Burden 21,104 43,127    
$9,897,100    

(a) MMS specifically solicits comments on the following questions:

(1) Is the proposed collection of information necessary for MMS to properly perform its functions, and will it be useful?

(2) Are the estimates of the burden hours of the proposed collection reasonable?

(3) Do you have any suggestions that would enhance the quality, clarity, or usefulness of the information to be collected?

(4) Is there a way to minimize the information collection burden on those who are to respond, including the use of appropriate automated electronic, mechanical, or other forms of information technology?

(b) In addition, the PRA requires agencies to estimate the total annual reporting and recordkeeping “non-hour cost” burden resulting from the collection of information. Other than the cost recovery fees listed in the burden table, and the fee for installing flaring/venting meters (§ 250.1163), we have not identified any other costs, and we solicit your comments on this item. For reporting and recordkeeping only, your response should split the cost estimate into two components: (1) Total capital and startup cost component and (2) annual operation, maintenance, and purchase of services components. Your estimates should consider the costs to generate, maintain, disclose or provide the information. You should describe the methods you use to estimate major cost factors, including system and technology acquisition, expected useful life of capital equipment, discount rate(s), and the period over which you incur costs. Capital and start-up costs include, among other items, computers and software you purchase to prepare for collecting information; monitoring, sampling, drilling, and testing equipment; and record storage facilities. Generally, our estimates should not include equipment or services purchased: before October 1, 1995; to comply with requirements not associated with the information collection; for reasons other than to provide information or keep records for the Government; or as part of customary and usual business or private practices.

National Environmental Policy Act (NEPA) of 1969

We analyzed this proposed rule in accordance with the criteria of the NEPA and 516 Departmental Manual 6, Appendix 10.4C, “issuance, and/or modification of regulations.” MMS completed a Categorical Exclusion Review (CER) for this action on May 31, 2005, and concluded: “The proposed rulemaking does not represent an exception to the established criteria for categorical exclusion. Therefore, preparation of an environmental document will not be required, and further documentation of this CER is not required.”

Energy Supply, Distribution, or Use (Executive Order 13211)

Executive Order 13211 requires the agency to prepare a Statement of Energy Effects when it takes a regulatory action that is identified as a significant energy action. This proposed rule is not a significant energy action, and therefore would not require a Statement of Energy Effects because it:

a. Is not a significant regulatory action under E.O. 12866,

b. Is not likely to have a significant adverse effect on the supply, distribution, or use of energy, and

c. Has not been designated by the Administrator of the Office of Information and Regulatory Affairs, OMB, as a significant energy action.

Consultation With Indian Tribes (Executive Order 13175)

Under the criteria in E.O. 13175, we have evaluated this proposed rule and determined that it has no potential effects on federally recognized Indian tribes. There are no Indian or tribal lands on the OCS.

Clarity of This Regulation (Executive Order 12866)

Executive Order 12866 requires each agency to write regulations that are easy to understand. MMS invites your comments on how to make this proposed rule easier to understand, including answers to questions such as the following:

(1) Are the requirements in the proposed rule clearly stated?

(2) Does the proposed rule contain technical language or jargon that interferes with its clarity?

(3) Does the format of the proposed rule (grouping and order of sections, use of headings, paragraphs, etc.) aid or reduce its clarity?

(4) Is the description of the proposed rule in the “Supplementary Information” section of this preamble helpful in understanding the rule?

Send a copy of any comments that concern how we could make this proposed rule easier to understand to: Office of Regulatory Affairs; Department of the Interior, Room 7229; 1849 C Street, NW., Washington, DC 20240. You may also e-mail the comments to this address: Exsec@ios.doi.gov.

List of Subjects in 30 CFR Part 250 Back to Top

Dated: January 31, 2007.

C. Stephen Allred,

Assistant Secretary—Land and Minerals Management.

For the reasons stated in the preamble, Minerals Management Service (MMS) proposes to revise 30 CFR part 250 as follows:

begin regulatory text

PART 250—OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL SHELF Back to Top

1. The authority citation for part 250 continues to read as follows:

Authority:

43 U.S.C. 1331 et seq.; 31 U.S.C. 9701.

2. Amend § 250.105 to revise the definition of “Sensitive reservoir” and add in alphabetical order definitions for “Flaring” and “Venting” to read as follows:

§ 250.105 Definitions.

* * * * *

Flaring means the burning of gas in the field as it is released into the atmosphere.

* * * * *

Sensitive reservoir means a reservoir in which high reservoir production rates will decrease ultimate recovery.

* * * * *

Venting means the release of gas into the atmosphere without igniting it. This includes gas that is released underwater and bubbles to the atmosphere.

* * * * *

3. In § 250.125, revise the table in paragraph (a) to read as follows:

§ 250.125 Service fees.

(a) * * *

Service Fee Table Back to Top
Service—processing of the following: Fee amount 30 CFR citation
Change in Designation of Operator $150 § 250.143.
Suspension of Operations/Suspension of Production (SOO/SOP) Request $1,800 § 250.171.
Exploration Plan (EP) $3,250 for each surface location, no fee for revisions § 250.211.
Development and Production Plan (DPP) or Development Operations Coordination Document (DOCD) $3,750 for each well proposed, no fee for revisions § 250.241(e).
Deepwater Operations Plan $3,150 § 250.292(p).
Conservation Information Document $24,200 § 250.296(a).
Application for Permit to Drill (APD; Form MMS-123) $1,850  
Initial applications only, no fee for revisions § 250.410(d); § 250.411; § 250.460; § 250.513(b); § 250.515; § 250.1605; § 250.1617(a); § 250.1622.
Application for Permit to Modify (APM; Form MMS-124) $110 § 250.460; § 250.465(b); § 250.513(b); § 250.515; § 250.613(b); § 250.615; § 250.1618(a); § 250.1622; § 250.1704(g).
New Facility Production Safety System Application for facility with more than 125 components $4,750  
A component is a piece of equipment or ancillary system that is protected by one or more of the safety devices required by API RP 14C (incorporated by reference as specified in § 250.198) § 250.802(e).
(Additional fee of $12,500 will be charged if MMS deems it necessary to visit a facility offshore; and $6,500 to visit a facility in a shipyard)  
New Facility Production Safety System Application for facility with 25-125 components $1,150 (Additional fee of $7,850 will be charged if MMS deems it necessary to visit a facility offshore; and $4,500 to visit a facility in a shipyard) § 250.802(e).
New Facility Production Safety System Application for facility with fewer than 25 components $570 § 250.802(e).
Production Safety System Application—Modification with more than 125 components reviewed $530 § 250.802(e).
Production Safety System Application—Modification with 25-125 components reviewed $190 § 250.802(e).
Production Safety System Application—Modification with fewer than 25 components reviewed $80 § 250.802(e).
Platform Application—Installation—under the Platform Verification Program $19,900 § 250.905(k).
Platform Application—Installation—Fixed Structure Under the Platform Approval Program $2,850 § 250.905(k).
Platform Application—Installation—Caisson/Well Protector $1,450 § 250.905(k).
Platform Application—Modification/Repair $3,400 § 250.905(k).
New Pipeline Application (Lease Term) $3,100 § 250.1000(b).
Pipeline Application—Modification (Lease Term) $1,800 § 250.1000(b).
Pipeline Application—Modification (ROW) $3,650 § 250.1000(b).
Pipeline Repair Notification $340 § 250.1008(e).
Pipeline Right-of-Way (ROW) Grant Application $2,350 § 250.1015.
Pipeline Conversion of Lease Term to ROW $200 § 250.1015.
Pipeline ROW Assignment $170 § 250.1018.
500 Feet From Lease/Unit Line Production Request $3,300 § 250.1156.
Gas Cap Production Request $4,200 § 250.1157.
Downhole Commingling Request $4,900 § 250.1158.
Complex Surface Commingling and Measurement Application $3,550 § 250.1202(a); § 250.1203(b); § 250.1204(a).
Simple Surface Commingling and Measurement Application $1,200 § 250.1202(a); § 250.1203(b); § 250.1204(a).
Voluntary Unitization Proposal or Unit Expansion $10,700 § 250.1303.
Unitization Revision $760 § 250.1303.
Application to Remove a Platform or Other Facility $4,100 § 250.1727.
Application to Decommission a Pipeline (Lease Term) $1,000 § 250.1751(a) or § 250.1752(a).
Application to Decommission a Pipeline (ROW) $1,900 § 250.1751(a) or § 250.1752(a).

* * * * *

4. Revise subpart K to read as follows:

Subpart K—Oil and Gas Production Requirements Back to Top

General Back to Top

§ 250.1150 What are the general reservoir production requirements?

You must produce wells and reservoirs at rates that provide for economic development without harming ultimate recovery and without adversely affecting correlative rights.

Well Tests and Surveys Back to Top

§ 250.1151 How often must I conduct well production tests?

(a) You must conduct well production tests as shown in the following table:

You must conduct: And you must submit to the Regional Supervisor:
(1) A well-flow potential test on all new, recompleted, or reworked well completions within 30 days of the date of first continuous production Form MMS-126, Well Potential Test Report, along with the supporting data as listed in the table in § 250.1167, within 15 days after the end of the test period.
(2) At least one well test during a calendar half-year for each producing completion Results on Form MMS-128, Semiannual Well Test Report, of the most recent well test obtained. This must be submitted within 45 days after the end of the calendar half-year

(b) You may request an extension from the Regional Supervisor if you cannot submit the results of a semiannual well test within the specified time.

(c) You must submit an original and one copy of the form required by paragraph (a) of this section, as listed in the table in § 250.1167. You must include one public information copy with each submittal in accordance with §§ 250.190 and 250.196, and mark that copy “Public Information.”

§ 250.1152 How do I conduct well tests?

(a) When you conduct well tests you must:

(1) Recover fluid from the well completion equivalent to the amount of fluid introduced into the formation during completion, recompletion, reworking, or treatment operations before you start a well test;

(2) Produce the well completion under stabilized rate conditions for at least 6 consecutive hours before beginning the test period;

(3) Conduct the test for at least 4 consecutive hours;

(4) Adjust measured gas volumes to the standard conditions of 14.73 pounds per square inch absolute (psia) and 60°F for all tests; and

(5) Use measured specific gravity values to calculate gas volumes.

(b) You may request approval from the Regional Supervisor to conduct a well test using alternative procedures if you can demonstrate test reliability under those procedures.

(c) The Regional Supervisor may also require you to conduct the following tests and complete them within the specified time period:

(1) A retest or a prolonged test of a well completion if it is determined to be necessary for the proper establishment of a Maximum Production Rate (MPR) or a Maximum Efficient Rate (MER); and

(2) A multipoint back-pressure test to determine the theoretical open-flow potential of a gas well.

(d) An MMS representative may witness any well test. Upon request, you must provide advance notice to the Regional Supervisor of the times and dates of well tests.

§ 250.1153 When must I conduct a static bottomhole pressure survey?

(a) You must conduct a static bottomhole pressure survey under the following conditions:

If you have: Then you must conduct:
(1) A new producing reservoir A static bottomhole pressure survey within 90 days after the date of first continuous production.
(2) A reservoir with three or more producing completions Annual static bottomhole pressure surveys in a sufficient number of key wells to establish an average reservoir pressure. The Regional Supervisor may require that bottomhole pressure surveys be performed on specific wells.

(b) Your bottomhole pressure survey must meet the following requirements:

(1) You must shut-in the well for a minimum period of 4 hours to ensure stabilized conditions; and

(2) The bottomhole pressure survey must consist of a pressure measurement at mid-perforation, and pressure measurements and gradient information for at least four gradient stops coming out of the hole.

(c) You must submit to the Regional Supervisor the results of all static bottomhole pressure surveys on Form MMS-140, Bottomhole Pressure Survey Report, within 60 days after the date of the survey.

(d) The Regional Supervisor may grant a departure from the requirement to run a static bottomhole pressure survey. You must request a departure by letter, along with Form MMS-140, Bottomhole Pressure Survey Report. You must include sufficient justification to support the departure request.

Classifying Reservoirs Back to Top

§ 250.1154 How do I determine if my reservoir is sensitive?

(a) You must determine whether each reservoir is sensitive. You must classify the reservoir as sensitive if:

(1) Under initial conditions it is an oil reservoir with an associated gas cap;

(2) At any time there are near-critical fluids; or

(3) The reservoir is undergoing secondary or tertiary recovery.

(b) For the purposes of this subpart, near-critical fluids are those fluids that occur in high temperature, high-pressure reservoirs where it is not possible to define the liquid-gas contact or fluids in reservoirs that are near bubble point or dew point conditions.

(c) The Regional Supervisor may reclassify a reservoir when available information warrants reclassification.

(d) If available information indicates that a reservoir previously classified as non-sensitive is now sensitive, you must submit a request to the Regional Supervisor to reclassify the reservoir. You must include supporting information, as listed in the table in § 250.1167, with your request.

(e) If information indicates that a reservoir previously classified as sensitive is now non-sensitive, you may submit a request to the Regional Supervisor to reclassify the reservoir. You must include supporting information, as listed in the table in § 250.1167, with your request.

§ 250.1155 What information must I submit for sensitive reservoirs?

You must submit an original and three copies of Form MMS-127 and supporting information, as listed in the table in § 250.1167 to the Regional Supervisor. You must include one public information copy with each submittal in accordance with §§ 250.190 and 250.196, and mark that copy “Public Information.” You must submit this information:

(a) Within 45 days after beginning production from the reservoir or discovering that it is sensitive;

(b) At least once during the calendar year;

(c) Within 45 days after you revise reservoir parameters; and

(d) Within 45 days after the Regional Supervisor classifies the reservoir as sensitive under § 250.1154(c).

Approvals Prior to Production Back to Top

§ 250.1156 What steps must I take to receive approval to produce within 500 feet of a unit or lease line?

(a) You must obtain approval from the Regional Supervisor before you start producing from a well that has any portion of the completed interval less than 500 feet from a unit or lease line. Submit to MMS the service fee listed in § 250.125 and the Regional Supervisor will determine whether approval of your request will maximize ultimate recovery, avoids the waste of natural resources or whether it is necessary to protect correlative rights. You do not need to obtain approval if the adjacent leases or units have the same unit, lease, and royalty interests as the lease or unit you plan to produce. You do not need to obtain approval if the adjacent block is unleased.

(b) You must notify the operator(s) of adjacent property(ies) that are within 500 feet of the completion, if the adjacent acreage is a leased block in the Federal OCS. You must provide the Regional Supervisor proof of the date of the notification. The operators of the adjacent properties have 30 days after receiving the notification to provide the Regional Supervisor letters of acceptance or objection. If an adjacent operator does not respond within 30 days, the Regional Supervisor will presume there are no objections and proceed with a decision. The notification must include:

(1) The well name;

(2) The rectangular coordinates (x, y) of the location of the top and bottom of the completion or target completion reference to the North American Datum 1983, and the subsea depths of the top and bottom of the completion or target completion;

(3) The distance from the completion or target completion to the unit or lease line at its nearest point; and

(4) A statement indicating whether or not it will be a high-capacity completion having a perforated or open hole interval greater than 150 feet measured depth.

§ 250.1157 How do I receive approval to produce gas from an oil reservoir with an associated gas cap?

You must request and receive written approval from the Regional Supervisor before producing gas from each completion in an oil reservoir that is known to have an associated gas cap. If the oil reservoir is not initially known to have an associated gas cap, but your oil well begins to show characteristics of a gas well, you must request and receive written approval from the Regional Supervisor to continue producing the well. You must include the service fee listed in § 250.125 and the supporting information, as listed in the table in § 250.1167, with your request.

§ 250.1158 How do I receive approval to downhole commingle hydrocarbons?

(a) Before you perforate a well, you must request and receive approval from the Regional Supervisor to commingle hydrocarbons produced from multiple reservoirs within a common wellbore. The Regional Supervisor will determine whether your request maximizes ultimate recovery and avoids the waste of natural resources. You must include the service fee listed in § 250.125 and the supporting information, as listed in the table in § 250.1167, with your request.

(b) If one or more of the commingled reservoirs is a competitive reservoir, you must notify the operators of all leases that contain the reservoir that you intend to downhole commingle the reservoirs. Your request for approval of downhole commingling must include proof of the date of this notification. The notified operators have 30 days after notification to provide the Regional Supervisor with letters of acceptance or objection. If the notified operators do not respond within the specified period, the Regional Supervisor will assume the operators do not object and proceed with a decision.

Production Rates Back to Top

§ 250.1159 May the Regional Supervisor limit my well or reservoir production rates?

(a) The Regional Supervisor may set a Maximum Production Rate (MPR) for a producing well completion, or set a Maximum Efficient Rate (MER) for a reservoir, or both, if the Regional Supervisor determines that an excessive production rate could harm ultimate recovery. An MPR or MER will be based on well tests and any limitations imposed by well and surface equipment, sand production, reservoir sensitivity, gas-oil and water-oil ratios, location of perforated intervals, and prudent operating practices.

(b) If the Regional Supervisor sets an MPR for a producing well completion, or an MER for a reservoir, you may not exceed those rates except due to normal variations and fluctuations in production rates, as set by the Regional Supervisor.

Flaring, Venting, and Burning Hydrocarbons Back to Top

§ 250.1160 When may I flare or vent gas?

(a) You must receive approval from the Regional Supervisor to flare or vent oil-well gas or gas-well gas at your facility, except in the following situations:

Condition Additional requirements
(1) When the gas is lease use gas (produced natural gas which is used on or for the benefit of lease operations such as gas used to operate production facilities) or is used as an additive necessary to burn waste products, such as H 2 S The volume of gas flared or vented may not exceed the amount necessary for its intended purpose. Burning waste products may require approval under other regulations.
(2) During the restart of a facility that was shut in because of weather conditions, such as a hurricane Flaring or venting may not exceed 48 cumulative hours without Regional Supervisor approval.
(3) During the blow down of transportation pipelines downstream of the royalty meter (i) You must report the location, time, flare/vent volume, and reason for flaring/venting to the Regional Supervisor in writing within 72 hours after the incident is over.
(ii) Additional approval may be required under subparts H and J of this part.
(4) During the unloading or cleaning of a well, drill-stem testing, production testing, other well-evaluation testing, or the necessary blow down to perform these procedures You may not exceed 48 cumulative hours of flaring or venting per testing operation on a single completion without Regional Supervisor approval.
(5) When properly working equipment yields flash gas (natural gas released from liquid hydrocarbons as a result of a decrease in pressure, an increase in temperature, or both) from storage vessels or other low-pressure production vessels, and you cannot economically recover this flash gas You may not flare or vent more than an average 50 MCF per day during any calendar month without Regional Supervisor approval.
(6) When the equipment works properly but there is a temporary upset condition, such as a hydrate or paraffin plug (i) For oil-well gas and gas-well flash gas (natural gas released from condensate as a result of a decrease in pressure, an increase in temperature, or both), you may not exceed 48 continuous hours of flaring or venting without Regional Supervisor approval.
(ii) For primary gas-well gas (natural gas from a gas well completion that is at or near its wellhead pressure; this does not include flash gas), you may not exceed 2 continuous hours of flaring or venting without Regional Supervisor approval.
(iii) You may not exceed 144 cumulative hours of flaring or venting during a calendar month without Regional Supervisor approval.
(7) When equipment fails to work properly, including equipment maintenance and repair, or when you must relieve system pressures (i) For oil-well gas and gas-well flash gas, you may not exceed 48 continuous hours of flaring or venting without Regional Supervisor approval. (ii) For primary gas-well gas, you may not exceed 2 continuous hours of flaring or venting without Regional Supervisor approval.
(iii) You may not exceed 144 cumulative hours of flaring or venting during a calendar month without Regional Supervisor approval.
(iv) The continuous and cumulative hours allowed under this paragraph may be counted separately from the hours under paragraph (a)(6) of this section.

(b) You must inform the Regional Supervisor and receive approval to flare or vent gas before you exceed the volume specified in your Development and Production Plan submitted under subpart B of this part, even if the flaring or venting does not require approval under paragraph (a) of this section. The Regional Supervisor will determine whether your proposed flaring or venting complies with air emission thresholds under subpart C of this part.

(c) The Regional Supervisor may establish alternative approval procedures to cover situations where you cannot contact the MMS office, such as during non-office hours.

(d) The Regional Supervisor may specify a volume limit, or a shorter time limit than specified elsewhere in this part, in order to prevent air quality degradation or loss of reserves.

(e) The Regional Supervisor will evaluate your request for gas flaring or venting and determine if the loss of hydrocarbons is due to negligence, or could be avoided.

(f) If you flare or vent gas without the required approval, or if the Regional Supervisor determines that you were negligent or could have avoided flaring or venting the gas, the hydrocarbons will be considered avoidably lost or wasted. You must pay royalties on the loss or waste, according to part 202 of this title. You must value any gas or liquid hydrocarbons avoidably lost or wasted under the provisions of part 206 of this title.

§ 250.1161 When may I flare or vent gas for extended periods of time?

You may flare or vent oil-well gas and gas-well flash gas for a period that the Regional Supervisor will specify, and which will not exceed 1 year, if the Regional Supervisor approves your request for one of the following reasons:

(a) You initiate an action which, when completed, will eliminate flaring and venting;

(b) You submit to the Regional Supervisor an evaluation supported by engineering, geologic, and economic data indicating that the oil and gas produced from the well(s) will not economically support the facilities necessary to sell the gas; or to use the gas on or for the benefit of, the lease; or

(c) The Regional Supervisor determines that an improperly working valve, pipe fitting, or similar component results in flaring or venting of less than 10 MCF per day, and that it is prudent to repair the leak at a later date. The Regional Supervisor may exempt this flaring or venting from the time limits set in § 250.1160.

§ 250.1162 When may I burn produced liquid hydrocarbons?

(a) You must request and receive approval from the Regional Supervisor to burn any produced liquid hydrocarbons. The Regional Supervisor may allow you to burn condensate if you demonstrate that transporting it to market or re-injecting it is not feasible or poses a significant risk of harm to offshore personnel or the environment. In most cases, the Regional Supervisor will not allow you to burn more than 300 barrels of condensate in total during unloading or cleaning of a well, drill-stem testing, production testing, or other well-evaluation testing.

(b) The Regional Supervisor will evaluate your request for liquid hydrocarbon burning, and determine if the loss of hydrocarbons is due to negligence or could be avoided.

(c) If you burn liquid hydrocarbons without the required approval, or if the Regional Supervisor determines that you were negligent or could have avoided burning liquid hydrocarbons, the hydrocarbons will be considered avoidably lost or wasted. You must pay royalties on the loss or waste, according to part 202 of this title. You must value any liquid hydrocarbons avoidably lost or wasted under the provisions of part 206 of this title.

§ 250.1163 How must I measure gas flaring or venting volumes and liquid hydrocarbon burning volumes and what records must I maintain?

(a) If your facility processes more than an average of 2,000 BOPD during [MONTH AND YEAR IN WHICH FINAL RULE IS PUBLISHED], you must install flare/vent meters within 120 days after [THE MONTH AND YEAR IN WHICH THE FINAL RULE IS PUBLISHED]. If your facility processes more than an average of 2,000 BOPD during a calendar month after [MONTH AND YEAR IN WHICH FINAL RULE IS PUBLISHED], you must install flare/vent meters within 90 days after the end of the month in which the average amount of oil processed exceeds 2,000 BOPD.

(1) The flare/vent meters must measure all flared and vented gas within 2 percent accuracy.

(2) You must calibrate the meters regularly, in accordance with the manufacturer's recommendation, or at least once every 6 months, whichever is shorter.

(b) You must report all hydrocarbons produced from a well completion, including all gas flared, gas vented, and liquid hydrocarbons burned, to Minerals Revenue Management on Form MMS-4054 (Oil and Gas Operations Report), in accordance with § 216.53 of this title.

(1) You must report the amount of gas flared and the amount of gas vented separately.

(2) You may classify and report gas used to operate equipment on the facility (such as gas used to power engines, gas used as pilot lights, instrument gas, purge gas used to prevent oxygen from entering the flare or vent stack, sparge gas used to regenerate glycol, and blanket gas used to maintain pressure in low pressure vessels) as lease use gas.

(3) You must report the amount of gas flared and vented at each facility on a lease or unit basis. Gas flared and vented from multiple facilities on a single lease or unit must be reported separately.

(c) You must prepare and maintain records detailing gas flaring, gas venting, and liquid hydrocarbon burning for each facility. You must maintain these records for the period specified in part 212 of this title. You must keep these records on the facility for 2 years and have them available for inspection by MMS representatives. After 2 years, you must maintain the records, allow MMS representatives to inspect the records upon request, and provide copies to the Regional Supervisor upon request, but you are not required to keep them on the facility. The records must include, at a minimum:

(1) Daily volumes of gas flared, gas vented, and liquid hydrocarbons burned;

(2) Number of hours of gas flaring, gas venting, and liquid hydrocarbon burning, on a daily basis;

(3) A list of the wells contributing to gas flaring, gas venting, and liquid hydrocarbon burning, along with gas-oil ratio data;

(4) Reasons for gas flaring, gas venting, and liquid hydrocarbon burning; and

(5) Documentation of all required approvals.

(d) If your facility is required to have flare/vent meters, you must maintain the meter recordings for the period specified in §§ 212.50 and 212.51 of this title. You must keep these recordings on the facility for 2 years and have them available for inspection by MMS representatives. After 2 years, you must maintain the recordings, allow MMS representatives to inspect the recordings upon request, and provide copies to the Regional Supervisor upon request, but are not required to keep them on the facility. These recordings must include the begin times, end times, and volumes for all flaring and venting incidents.

(e) If your flaring or venting of gas, or burning of liquid hydrocarbons, required written or oral approval, you must submit documentation to the Regional Supervisor summarizing the location, dates, number of hours, and volumes of gas flared, gas vented, and liquid hydrocarbons burned under the approval, as required under § 250.140.

§ 250.1164 What are the requirements for flaring or venting gas containing H

(a) You may not vent gas containing H 2 S, except for minor releases during maintenance and repair activities that do not result in a 15-minute time-weighted average atmosphere concentration of H 2 S of 20 ppm or higher anywhere on the platform.

(b) You may flare gas containing H 2 S only if you meet the requirements of §§ 250.1160, 250.1161, 250.1163, and the following additional requirements:

(1) You may not emit more than 15 lbs of SO 2 per hour per mile from shore, without approval from the Regional Supervisor;

(2) For safety or air pollution prevention purposes, the Regional Supervisor may further restrict the flaring of gas containing H 2 S. The Regional Supervisor will use information provided in the lessee's H 2 S Contingency Plan (§ 250.490(f)), Exploration Plan, Development and Production Plan, Development Operations Coordination Document, and associated documents to determine the need for restrictions; and

(3) 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 you to conduct an air quality modeling analysis to determine the potential effect of facility emissions. The Regional Supervisor may require monitoring and reporting, or may restrict or prohibit flaring, under §§ 250.303 and 250.304.

(c) You must report flared and vented gas containing H 2 S as required under § 250.1163. In addition, the Regional Supervisor may require you to submit monthly reports of flared and vented gas containing H 2 S. Each report must contain, on a daily basis:

(1) The volume and duration of each flaring and venting occurrence;

(2) H 2 S concentration in the flared or vented gas; and

(3) The calculated amount of SO 2 emitted.

Enhanced Recovery Back to Top

§ 250.1165 What must I do for enhanced recovery operations?

(a) You must promptly initiate enhanced oil and gas recovery operations for all reservoirs where these operations would result in increased ultimate recovery of oil or gas under sound engineering and economic principles.

(b) Before initiating enhanced recovery operations, you must submit a proposed plan to the Regional Supervisor and receive approval for pressure maintenance, secondary or tertiary recovery, cycling, and similar recovery operations intended to increase the ultimate recovery of oil and gas from a reservoir. The proposed plan must include, for each project reservoir, a brief geologic and engineering overview, structure map, well log section, Form MMS-127, and any additional information required by the Regional Supervisor.

(c) You must report to Minerals Revenue Management the volumes of oil, gas, or other substances injected, produced, or produced for a second time under § 216.53 of this title.

Special Alaska OCS Region Requirements Back to Top

§ 250.1166 What additional reporting is required for developments in the Alaska OCS Region?

(a) For any development in the Alaska OCS Region, you must submit an annual reservoir management report to the Regional Supervisor. The report must contain information detailing the activities performed during the previous year and planned for the upcoming year that will provide for:

(1) The prevention of waste;

(2) The protection of correlative rights; and

(3) A greater ultimate recovery of oil and gas.

(b) If your development is jointly regulated by MMS and the State of Alaska, MMS and the AOGCC will jointly determine appropriate reporting requirements to minimize or eliminate duplicate reporting requirements.

(c) Every time you are required to submit Form MMS-127 under § 250.1155, you must request an MER for each producing sensitive reservoir in the Alaska OCS Region, unless otherwise instructed by the Regional Supervisor.

Information Needed With Forms and for Approvals Back to Top

§ 250.1167 What information must I submit with forms and for approvals?

You must submit the supporting information listed in the following table with the forms and for the approvals required under this subpart:

WPT MMS-126 SRI MMS-127 Gas cap production Downhole commingling Reservoir reclassification Production within 500-ft of a Unit or Lease Line
† Each Gas Cap Production request and Downhole Commingling request should include the estimated recoverable reserves for (1) the case where your proposed production scenario is approved, and (2) the case where your proposed production scenario is denied.
* Additional items the Regional Supervisor may request.
Note: All maps must be at a standard scale and show lease and unit lines. If you have not generated all of the required data for your own purposes, you may submit those data you have available for consideration.
(a) Maps:            
(1) Base map with surface, bottomhole, and completion locations with respect to the unit or lease line and the orientation of representative seismic lines or cross sections
(2) Structure maps with penetration point and subsea depth for each well penetrating the reservoirs, highlighting subject wells; reservoir boundaries; and original and current fluid levels
(3) Net sand isopach with total net sand penetrated for each well, identified at the penetration point
(4) Net hydrocarbon isopach with net feet of pay for each well, identified at the penetration point
(b) Seismic data:            
(1) Representative seismic lines, including strike and dip lines that confirm the structure; indicate polarity
(2) Time/depth correlation table for seismic data
(3) Amplitude extraction of seismic horizon, if applicable
(c) Logs:            
(1) Well log sections with tops and bottoms of the reservoir(s) and proposed or existing perforations
(2) Structural cross-sections showing the subject well and nearby wells
(d) Engineering Data:            
(1) Estimated recoverable reserves for each well completion in the reservoir; total recoverable reserves for each reservoir; method of calculation; reservoir parameters used in volumetric and decline curve analysis
(2) Well schematics showing current and proposed conditions
(3) The drive mechanism of each reservoir
(4) Pressure data, by date, and whether they are estimated or measured
(5) Production data and decline curve analysis indicative of the reservoir performance
(6) Reservoir simulation with the reservoir parameters used, history matches, and prediction runs (include proposed development scenario) * * * *
(e) General information:            
(1) Detailed economic analysis * *
(2) Reservoir name and whether or not it is competitive as defined under § 250.105
(3) Operator name, lessee name(s), block, lease number, royalty rate, and unit number (if applicable) of all relevant leases
(4) Brief geologic overview of project
(5) Explanation of why the proposed completion scenario will not harm ultimate recovery
(6) List of all wells in subject reservoirs that have ever produced or been used for injection

(f) Depending on the above requirement, you must submit appropriate payment of the service fee(s) listed in § 250.125.

end regulatory text

[FR Doc. E7-3846 Filed 3-5-07; 8:45 am]

BILLING CODE 4310-MR-P

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