2010-8798. Oil and Gas and Sulphur Operations in the Outer Continental Shelf-Oil and Gas Production Requirements

AGENCY:

Minerals Management Service (MMS), Interior.

ACTION:

Final rule.

SUMMARY:

The MMS is amending the regulations regarding oil and natural gas production requirements. This is a complete rewrite of these regulations, addressing issues such as production rates, burning oil, and venting and flaring natural gas, to ensure appropriate development of these natural resources. The final rule eliminates most restrictions on production rates and clarifies limits on the amount of natural gas that can be flared or vented. The final rule is written using plain language, so it is easier to read and understand.

DATES:

Effective Date: This rule is effective on May 19, 2010.

FOR FURTHER INFORMATION CONTACT:

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

SUPPLEMENTARY INFORMATION:

Background

Notice of Proposed Rulemaking

On March 6, 2007, the MMS published a Notice of Proposed Rulemaking (NPR) in the Federal Register (72 FR 9884). This NPR requested comments on proposed revisions to 30 CFR part 250, subpart K, Oil and Gas Production Rates. The MMS accepted comments on the NPR until June 4, 2007 (90 days). We received eight comments on the NPR. These comments came from producers of oil and natural gas in the Outer Continental Shelf (OCS) and from the State of Alaska. The MMS made revisions to the proposed rule based on these comments.

Mandate of the Outer Continental Shelf Lands Act

Under the OCS Lands Act (OCSLA), MMS has the responsibility to issue regulations governing oil and natural gas production operations on the OCS. Our regulations related to oil and natural gas operations are primarily based on three responsibilities given to the MMS by the OCSLA, these include:

1. Safety;

2. Protection of the environment; and

3. Conservation of resources.

The primary purpose of the final rule is to establish criteria for oil and natural gas production to ensure conservation of resources. These regulations help ensure that the American people received the maximum benefit from oil and natural gas production by maximizing the amount of oil and natural gas that is produced and marketed. For example, these regulations establish the criteria for natural gas flaring and venting and set limits on the time that natural gas may be flared or vented. These regulations are designed to work with other MMS regulations related to safety and protection of the environment and our other responsibilities under other Federal laws.

The MMS regulates air quality under the authority of the Clear Air Act (CAA), for areas in the Gulf of Mexico located west of 87.5° longitude (western Gulf of Mexico) and the Environmental Protection Agency (EPA) has authority for air quality elsewhere on the OCS. The MMS must coordinate with EPA to implement the CAA requirements. The EPA is responsible for setting National Ambient Air Quality Standards (NAAQS); MMS enforces those standards for oil and natural gas operations on the OCS. Our air quality requirements are located at 30 CFR subpart C—Pollution Prevention and Control. In addition to the Subpart C regulations, oil and gas operators must submit projected air emissions for their entire project as part of their Development and Production Plan (DPP) or their Development Operations Coordination Document (DOCD) at 30 CFR 250.249. Requests to flare or vent natural gas must not exceed the volume approved by MMS in the DPP or DOCD.

The MMS also reviews the flaring and venting requests to determine if they trigger an air quality review under 30 CFR subpart C. However, the flaring and venting limits set in these final regulations are low enough that additional air quality review is seldom required.

With regards to greenhouse gas emissions, MMS recognizes that this is an important issue. The CAA requires MMS to coordinate our air quality regulations with EPA. If EPA establishes a NAAQS for greenhouse gas emissions, MMS would be responsible for enforcing those standards in the western Gulf of Mexico and we would develop regulations to implement that authority under the regulations at 30 CFR subpart C, as appropriate.

Purpose of These Revisions

The MMS is revising subpart K to:

(1) Update the structure and readability of the rule, bringing it into compliance with the Department of the Interior (DOI) plain language guidance;

(2) Eliminate unnecessary requirements;

(3) Clarify limits on the amount of natural gas that may be flared or vented during certain situations;

(4) Improve collection of data on flaring and venting; and

(5) Incorporate several existing Notices to Lessees (NTLs).

The DOI requires agencies to write regulations in plain language, that is in a style that will ensure the regulations are easy to read and clear. The MMS follows DOI's plain language guidelines when creating new regulations or updating existing regulations. These regulations were originally written before plain language standards were required; we are updating the entire subpart to comply with those standards.

Some requirements from the current subpart K regulations are eliminated by the final rule because they are unnecessary in today's petroleum industry. For example, MMS required operators to establish maximum production rates (MPRs) for producing well completions, and maximum efficient rates (MERs) for producing reservoirs, in OCS Order No. 11 in 1974, Start Printed Page 20272during a period of oil shortages and energy crises. In 1988, MMS reduced the MER requirement. Currently, MERs 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 concluded that maximum rate requirements and production balancing requirements can be largely eliminated without detriment to efforts for conservation and maximization of ultimate recovery. However, the final rule will allow the Regional Supervisor to set production rates in cases where excessive production rates could harm ultimate recovery from the reservoir.

The final rule clarifies limits on the length of time of natural gas that may be flared or vented in certain situations. The final rule requires approval from the Regional Supervisor to flare or vent natural gas except for situations that are described in the rule. The situations that don't require Regional Supervisor approval (provided the activities are completed within a specific time frame in most cases) include:

(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 H₂ S.

(2) During the restart of a facility that was shut in because of weather conditions, such as a hurricane.

(3) During the blow down of transportation pipelines downstream of the royalty meter.

(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.

(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.

(6) When the equipment works properly but there is a temporary upset condition, such as a hydrate or paraffin plug.

(7) When equipment fails to work properly, including equipment maintenance and repair, or when you must relieve system pressures.

We explain the length of time that gas may be flared or vented for each situation and clarify when approval from the Regional Supervisor is required. Regardless of the reason for flaring or venting natural gas, the lessee or operator must report the amounts to MMS. The final rule requires separate reporting of the amount of natural gas flared and the amount of natural gas vented. This separate reporting requirement is in response the GAO report recommending that MMS collect these numbers separately. The MMS will publish the raw data on our Web site, along with other oil and natural gas production data. The Department of Energy's Energy Information Administration uses this production data for their statistics and analysis. This requirement will improve the quality of the data that is available on natural gas emissions.

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

There are several Notices to Lessees (NTLs) that will be rescinded when the final rule becomes effective. However, if necessary, MMS will issue additional NTLs to provide guidance. We will rescind the following NTLs:

NTL No. 97-16, Production Within 500 Feet of a Unit or Lease Line, effective August 1, 1997.
NTL No. 98-23, Interim Reporting Requirements for 30 CFR part 250, subpart K, Oil and Gas Production Rates, effective October 15, 1998.
NTL No. 99-G20, Downhole Commingling Applications, effective September 7, 1999.
NTL No. 2006-N06, Flaring and Venting Approvals, effective December 19, 2006.

This NTL also provides contact information for each Region and provides sample field records. These two items are not addressed in the final rule. The MMS will issue a new NTL to include only this information, after the effective date of this final rule.

GAO Report

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 concluded that more accurate records are needed on flaring and venting 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 report also stated that the impact of methane (a naturally occurring gas released during venting) on the earth's atmosphere is about 23 times greater than that of carbon dioxide (a byproduct of flaring). 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 consulting with EPA (Environmental Protection Agency), MMS, and BLM (Bureau of Land Management), on how to best collect separate statistics on flaring and venting.

The MMS conducted analyses to assess the costs and benefits of requiring flare/vent meters and 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 final 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 could be significant, and input from potentially affected parties is necessary. We requested comments on this issue in the proposed rule. Commenters pointed out that converting existing facilities that are equipped to vent natural gas to be able to flare natural gas may require significant redesign for safety. They also pointed out that there are many factors in determining whether to flare natural gas or vent natural when designing a facility. These factors include the operating philosophy, nature and type of reservoir, facility design limitations or capabilities, operating practices, safety, and economics. Industry comments were consistent in recommending that in addition to the considering requiring flaring instead of venting, that MMS work with them to find ways to reduce overall natural gas emissions. They also stated that a Start Printed Page 20273requirement for flaring instead of venting should be only for new facilities. They requested that MMS hold a workshop to discuss the issue. The MMS plans to work directly with interested parties to study the costs and benefits of requiring that companies flare the natural gas, whenever possible, when flaring or venting is necessary, as recommended in the GAO report. We will hold a workshop to discuss the issue of flaring instead of venting, shortly after this final rule is published. This workshop and additional cost-benefit analysis will consider greenhouse gas issues associated with flaring and venting. The workshop will be the first step in considering how to best implement this recommendation. The MMS will decide how to move forward with the rulemaking on flaring natural gas after we hold the workshop. Our next step would likely be an advance notice of proposed rulemaking to further vet our approach with industry and other stakeholders.

To improve data collection, as the GAO report suggested, MMS will require operators to report flaring and venting volumes to MMS separately. Previously, MMS only collected information on the total natural gas flared and vented. Operators did not need to differentiate between the two categories.

Oil and Gas Industry Contributions to Greenhouse Gases in the Federal OCS

Most natural gas production involves extracting natural gas from wells drilled into underground gas reservoirs; however, some natural gas is generated as a by-product of oil production. During oil and natural gas production it may become necessary to burn or release natural gas for a number of operational reasons, including safety. These operations may be associated with unloading or cleaning of a well, production testing, or relieving system pressure during equipment failure. The controlled burning of natural gas is called flaring, while the controlled release of unburned gases directly into the atmosphere is called venting. Most flaring and venting occurs at the end of a flare stack or boom which ensures that natural gas can be safely disposed of in emergency and shutdown situations. It is virtually impossible to produce oil and natural gas without any flaring or venting and it would be impractical to shut in production every time an upset occurs. It is estimated that operators in the Gulf of Mexico Outer Continental Shelf (OCS) flare and vent less than 0.5 percent of the gas produced, making this area a world leader in the conservation of natural gas resources.

Both flaring and venting on the OCS are highly regulated by the Minerals Management Service (MMS). Federal regulations (30 CFR 250, Subpart K) specify the limited circumstances under which offshore oil and gas operators may flare or vent natural gas. These final regulations strictly limit the amount of time operators may flare or vent. In some cases, operators request additional time in order to complete equipment repairs. We evaluate each of these requests on a case-by-case basis, with conservation as a primary focus.

Even though they are already a world leader, MMS continuously strives to improve our oversight of OCS flaring and venting. In most places around the world, for example, there is minimal reporting or tracking of flare and/or vent volumes. In the Federal OCS, MMS requires operators to continuously record these volumes and report them each month. These final regulations will require operators to install flare/vent meters on large platforms and also to report gas flared separately from gas vented. These regulatory changes would provide more accurate measurements of GHG emissions.

Given the existing restrictions on OCS flaring and venting, there is minimal opportunity to further reduce the overall volume of gas flared and vented. However, the global warming potential (GWP) of GHG emissions could be reduced if MMS were to require operators to flare instead of vent (when the release of natural gas is necessary). Such a requirement would reduce the GWP of GHG emissions by converting most methane to carbon dioxide as it is released. As previously stated, MMS is planning a workshop to address this topic.

It is difficult to estimate the impact that flaring instead of venting would have on GHG emissions until we begin to gather more accurate data from the requirement to install flare/vent meters and to report flare volumes separately from vent volumes. Furthermore, it is impractical, if not impossible, to eliminate all venting. Even if 100% of the released OCS gas could be flared instead of vented, the impact on total U.S. GHG emissions would be very small.

In 2005, U.S. greenhouse gas (GHG) emissions totaled 7.986 × 10 ⁹ tons of carbon dioxide equivalent (CO₂ e). Of that total, only 24.7 × 10 ⁶ tons of CO₂ e, or 0.31 percent, were related to OCS oil and gas production (including platform and non-platform sources), flaring and venting activities represent only a fraction of that amount. Under MMS oversight, OCS oil and gas operators are already ahead of the curve in terms of limiting GHG emissions.

Based on several assumptions, estimates, and existing analyses, MMS roughly approximated the impact that might occur if it were to mandate flaring over venting. These estimates indicate that such a requirement would reduce total US GHG emissions by less than 0.05%. However, the accuracy of these estimates will improve after the regulatory change becomes final. Reported OCS flare and vent volumes could increase or decrease based solely on improved reporting accuracy. In any event, further analysis may shed light on whether flaring rather than venting natural gas is cost effective from a greenhouse gas perspective, even if the total amount of greenhouse gases is small.

Public Comments on the Proposed Rule

The MMS received eight sets of comments on the NPR from industry trade groups and representatives and one comment from the State of Alaska. The MMS reviewed and responded to these comments as appropriate. To help convey the comments, we summarized and combined similar comments. The results are explained in the following two tables. Table 1 contains our responses to general comments and Table 2 addresses comments on specific sections.Start Printed Page 20274

Table 1—MMS Response to General Comments
Comment	MMS response
Measurement
(1) Measurement accuracy for flared or vented gas envisioned by rule is not achievable given the wide range of conditions to which the meter would be exposed.	The MMS agrees. We will revise the accuracy requirement from 2 percent to 5 percent. This is established technology in the North Sea and Canada, and a 5 percent accuracy requirement has been adopted by regulatory bodies in those regions. Also, flare/vent meters with this accuracy are already used on some Gulf of Mexico (GOM) facilities.
(2) Retrofitting may be a problem due to space limitations and safety concerns.	Installation of meters is necessary to improve oversight of MMS's flare/vent program. A cost-benefit analysis conducted by MMS supports GAO's recommendation to install meters on all facilities that process more than 2,000 bopd. The Regional Supervisor will work with operators on a case-by-case basis if a safety or space issue is demonstrated, as a departure under § 250.142.
(3) If deferment of this part of the rule is not acceptable, it is recommended that meters be limited to new facilities under construction 6 months after date that final rule is published.	Installation of meters is necessary to improve oversight of MMS's flare/vent program. The cost-benefit analysis concluded that meters on all facilities processing over 2,000 bopd is appropriate, not just new facilities. Also, metering flare/vent volumes on all (existing and future) facilities processing over 2,000 bopd better implements the GAO recommendations.
(4) Defer requirement to install meters on all offshore complexes processing 2,000 bopd to develop a best practice with industry that would have broad applicability to all facilities on the OCS, not just those processing 2,000 bopd.	The MMS has sufficient information to finalize the rule. Additional input from industry groups is not necessary and would delay implementation of GAO recommendations. We agree that there should be a best practice established for estimating volumes of gas flared or vented from facilities processing less than 2,000 bopd. However, metering is more accurate, and requiring meters on those facilities that process more than 2,000 bopd is consistent with the GAO recommendations.
(5) The number of facilities impacted by the rule has been underestimated since multiple facilities may be involved in processing/handling production streams.	The commenter did not provide an alternate, documented number; therefore, MMS must use our best analysis.
(6) Cost impact of the rule has been underestimated.	A higher cost estimate was provided by the commenter. We used the cost model that was submitted by the commenter in our cost-benefit analysis and determined that the difference is negligible and that a 2,000 bopd threshold for metering is still appropriate.
(7) Set a thousand cubic feet (MCF) volume per day vented, calculated by test, rather than having a mandatory metering system.	Volume estimates calculated from a test are far less accurate than metered volumes and would not achieve the improvements recommended by GAO.
(8) These meters should not be subject to the requirements of Subpart L.	Flare/vent meters are subject to the requirements of Subpart K.
(9) Cost is a huge burden to smaller facilities; increase meter requirement to facilities with average throughput of 10,000 bopd or more.	See responses (2) and (6). Also see discussion concerning the Regulatory Flexibility Act.
(10) Revise time to install meters from 120 days to 180 days to accommodate design, shipping, and labor.	The MMS agrees. We will revise the time allowed to install meters from 120 to 180 days for facilities processing more than 2,000 bopd when this final rule becomes effective. The time allowed to install meters on facilities that begin producing above 2,000 bopd, after this final rule is published, will also be revised from 90 to 120 days.
(11) Revise accuracy to 15 percent.	The MMS disagrees. See response (1).
(12) Meter high flow events, calculate others.	The MMS disagrees. See response (2).
(13) What if we don't have a flow when we schedule a calibration? Most of our flaring/venting is done during upset or emergency situations. Flare pilot must be kept on at all times, hence, inert gas such as nitrogen cannot be used as it will pose a safety issue by extinguishing the pilot flame.	At a minimum, calibration/verification of secondary devices associated with flare/vent meters can be performed in a no-flow situation in accordance with American Petroleum Institute's (API) Manual of Petroleum Measurement Standards (MPMS) Chapter 14 Section 10. Also, contingent upon the meter type, verification may include the performance of manufacturer recommended inspections and diagnostics. However, after further review, we determined that calibrating meters once a year is adequate.
(14) The time required to bring an existing facility into compliance would far exceed 120 days.	The MMS agrees. See response (10).
(15) Establish best practices for existing facilities to reduce overall levels of gas vented/flared.	The limits on flaring and venting set by these regulations are minimal, additional reductions in the levels of natural gas flared or vented would not reduce the need for meters. However, MMS does agree that industry should establish best practices for reducing the amount of natural gas flared or vented and we will include this topic as part of the flaring and venting workshop we are planning.
(16) Multiple meters would be required on most facilities.	The MMS anticipates 2 or 3 meters on most facilities where meters are required. That is, one for each pressure system (High Pressure (HP), Intermediate Pressure (IP), and Low Pressure (LP)) that exists on the facility. The meters would likely be located near the base of the flare boom just before the piping for that pressure system exits the facility.
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(17) Wait for completion of API RP on measurement and allocation.	The MMS has sufficient information to finalize the rule. As API Recommended Practices (RP) are published, MMS will consider incorporating these into our regulations.
(18) Future workshop should be planned to discuss solutions and best practices.	The MMS will hold a workshop after this final rule is issued. This will be included as a topic as part of our workshop on flaring and venting.
(19) Where did 2,000 bopd come from?	The MMS conducted a cost-benefit analysis looking at equipment costs, gas prices, and platform life to determine a minimum production rate that could support the installation of flare/vent meters. Also see Regulatory Flexibility Act discussion.
Flaring/Venting
(20) Converting to flare on existing facilities may require redesign for safety.	The MMS is still evaluating the flare versus vent issue and will hold an industry workshop to collect additional information.
(21) Limiting the flaring or venting of gas-well gas to 2 hours and allowing 48 continuous hours for oil-well gas when a hydrate plug forms is not consistent with prior guidance and actions. Previous MMS guidance made no distinction between gas-well gas and oil-well gas if the plug (hydrate) formed naturally.	We have always distinguished between gas-well gas and oil-well gas. The prior regulation stated that “lessees must not flare or vent gas-well gas beyond the time required to eliminate an emergency unless the Regional Supervisor approves.” MMS policy has consistently been to allow 2 hours to eliminate the flare or vent under this rule. We added an exception for hydrate plugs under § 250.1160(a)(6).
(22) Short comment period for response did not allow industry to develop detailed comments on flaring versus venting.	The MMS included information in the preamble on the flaring versus venting issue because it was addressed in the GAO report, and we wanted operators to be aware that MMS is considering possible changes to the regulations to address this issue in the future. The MMS is still evaluating this issue and we may hold a workshop to collect additional information, before proposing new regulations on this issue.
(23) Retain records for 2 years instead of 6 years.	There was no change proposed here; this is merely a clarification that existing law (30 U.S.C. 1713, implemented at 30 CFR part 212) applies to flare/vent records. Those records must be maintained for 6 years (in accordance with 30 U.S.C. 1713 and 30 CFR part 212), in addition to being maintained on the facility for 2 years and available for inspection by MMS personnel.
Miscellaneous
(24) How much of the MMS budget is being supported by the cost recovery program at this time; is an evaluation of the fee structure being carried out to adjust for actual agency needs?	The total discretionary budget for MMS in Fiscal Year 2007 was $288.2 million. Total revenue generated by cost recovery fees that year totaled $11.9 million or 4.1 percent of the total MMS discretionary budget. The MMS recently adjusted these fees by the Implicit Price Deflator for the Gross Domestic Product, as provided by regulation. The MMS plans to review cost recovery fees in the coming year. Should this review result in a need to change the fees significantly, rulemaking will be required and a proposed rule will be published in the Federal Register for public review and comment.
	Fees are established in accordance with the Independent Offices Appropriation Act of 1952, 31 U.S.C. 9701. It should be noted that MMS does not determine or adjust cost recovery fees to meet a pre-determined funding target, but rather to reflect the cost of actual services provided.
(25) The OOC, in conjunction with API, will commit to the development of a technical document or RP that would address quantification, including volume, mass, and composition of flare and vent quantities within the oil and gas production process. The OOC proposes to start working on this document now, concurrent with the subpart K final rulemaking; document and workshops to industry could occur within 18 months.	The MMS has sufficient information to finalize this final rule. As API RPs are published, MMS will consider incorporating these into our regulations.
(26) For the protection of the State of Alaska's correlative rights, require approval for operators to produce within 500 ft of a lease or unit line even if adjacent acreage is unleased, allow State to comment.	The MMS does not agree that this final rule violates State correlative rights. The MMS understands the State of Alaska's interest in protecting its correlative rights in the event of development and production from an OCS lease adjacent to State unleased lands. Under the MMS regulatory process, the State of Alaska will receive and will have the opportunity to comment on each OCS Development and Production Plan (DPP) (30 CFR part 250 subpart B). A DPP will include information on surface and bottom hole locations to enable the State of Alaska to determine if its correlative rights are at risk. The State of Alaska is entitled to copies of the Application(s) for Permit to Drill (APD) to monitor and assure that activities are conducted in accordance with an approved DPP.

Table 2—MMS Response to Comments on Specific Requirements
Citation/comment	MMS response
§ 250.1153(b)(2)—Consider completions with downhole gauges instead of requiring bottomhole pressure surveys	The MMS is not implementing this suggestion in the final rule. This configuration results in a single pressure measurement, which is not a survey. A survey is required in order to establish a pressure gradient, which is used to correct reservoir pressures to a common datum. As stated in § 250.1153(d), industry may continue to request departures from this requirement, if necessary.
§ 250.1160(a)—Add gas-well flash gas	Wording in the final rule will change from oil-well gas or gas-well gas to natural gas. This wording covers the venting or flaring of all natural gas regardless of the well type.
§ 250.1160(a)(3)(i)—Neither lease nor pipeline operator needs MMS approval to blowdown pipelines downstream of royalty meters	The commenter is correct, approval under this subpart will not be required for this situation since the activity is downstream of the royalty meter; however, flaring or venting must be reported after the fact in accordance with this final rule. Approvals may be required under subparts H and J of this part.
§ 250.1160(a)(4)—Include unloading or cleaning of a well in addition to testing under the Additional requirements column	The MMS agrees. The wording was modified to be consistent with the Condition column.
§ 250.1160(a)(5)—Define the amount of routine flaring or venting that is considered uneconomic	Since economic conditions vary with time, MMS cannot specify a fixed volume higher than 50 MCF per day. The Additional requirements column clearly indicates that a monthly average volume equal to 50 MCF per day or less is assumed by MMS to be uneconomic. If your facility averages more than 50 MCF per day, you will be expected to capture the gas or demonstrate that the volume is uneconomic and continue to monitor the economic viability as costs and prices change.
§ 250.1160(a)(6)—The time necessary to unload a well after an upset is remedied should be granted under § 250.1160(a)(4) and should not be included in the 48 continuous hours or 144 cumulative hours allowed under § 260.1160(a)(6) (upset due to hydrate plugs, etc.)	The initial cause of the problem will determine where the incident falls (either § 250.1160(a)(2), (a)(4), (a)(6), or (a)(7)). For example, an operator may flare oil-well gas without prior approval for 48 continuous hours in order to remediate a hydrate plug. However, that operator may not continue to flare without approval for an additional 48 hours in order to unload the well after the hydrate plug is remediated. In this example, the initial cause of the problem was a hydrate plug; therefore, the operator will only be authorized to flare oil-well gas for up to 48 continuous hours without approval (under § 250.1160(a)(6)).
§ 250.1160(a)(7)—The cumulative time allowed in paragraph (a)(4) should also be included in (a)(7)(iv). The hours accumulated to restore/optimize production should not impact the hours accrued due to equipment failures	The initial cause of the problem will determine where the incident falls (either § 250.1160(a)(2), (a)(4), (a)(6), or (a)(7)) and therefore the time allotted to perform the work related to the incident. If an equipment failure results in a need to flare or vent under § 250.1160(a)(7), any additional procedures needed to restore production (e.g., well blow down), must be performed within the time allotted under § 250.1160(a)(7). The operator would need to request approval from the Regional Supervisor if additional time is needed.
§ 250.1160(b)—Subpart C is sufficient to regulate pollution issues, mentioning Subpart C in Subpart K is redundant and confusing. Production upsets are not anticipated and therefore would not lend themselves to prior approval	The MMS agrees that it is not necessary to mention subpart C in subpart K. The MMS also agrees that production upsets may not lend themselves to prior approval. Paragraph (a) details the periods allowable during production upsets before MMS approval is required. Regardless of whether or not operators need and receive prior approval under (a), however, they are still obligated to follow their approved Development Operations Coordination Document (DOCD) or DPP under subpart B. We reworded § 250.1160(b) to clarify that MMS flare or vent approvals granted under subpart K do not exempt operators from the requirement to follow their DOCD or DPP. Before flaring and/or venting an amount that exceeds the limits specified in their DOCD or DPP, operators must submit and receive approval of a revised DOCD or DPP.
§ 250.1160(e)—If MMS approves flaring or venting, the volume should not be considered avoidably lost unless information provided was incorrect. Revise wording to state RS will evaluate flaring and venting requests to determine if situation exceeds those in § 250.1160(a)	The subject paragraph was eliminated since negligence related to flaring and venting is adequately covered in the subsequent paragraph.
§ 250.1160(f)—If MMS approves flaring or venting, the volume should not be considered avoidably lost unless information provided was incorrect. Revise wording to state flaring or venting in excess of situations in § 250.1160(a) without approval, or if approval was obtained with misleading information, will be considered avoidably lost	Additional wording referencing § 250.1160(a) is not necessary. Although MMS does not intend to commonly determine gas to be avoidably lost after we have approved the flaring or venting, the Regional Supervisor must retain full authority to make that determination.
§ 250.1161(c)—Industry supports addressing small leaks from valves, etc., if all safety concerns are addressed	The MMS agrees. Small leaks from valves, fittings, flanges, pressure relief valves or similar components are considered fugitive emissions and are more appropriately addressed under 30 CFR 250.107 (“What must I do to protect health, safety, property, and the environment?”). Note that this paragraph was reworded and renumbered as 30 CFR 250.1160(f).
§ 250.1162(a)—Include all liquid hydrocarbons, not just condensate	The MMS agrees. The word condensate will be replaced with liquid hydrocarbons.
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§ 250.1163(a)—Metering—defer this part until a workshop can be held with industry; work in conjunction with API to develop a Technical Bulletin; not enough time to retrofit existing facilities; high degree of measurement accuracy is unrealistic; if not deferred, limit to new facilities; and pulling a portion of the metering requirement may conflict with the Administration and Procedures Act	The MMS has sufficient information to finalize this rule. Additional input from industry groups is not necessary and would delay implementation of GAO recommendations. The meter accuracy requirement has been changed from 2 percent to 5 percent. We changed the time to install the meters on existing facilities from 120 days to 180 days based on an industry comment. Thus rulemaking is consistent with the Administrative Procedure Act (5 U.S.C. § 553, Rulemaking).
§ 250.1163(a)(3)—OGOR-B submitted to MRM will not accommodate multiple facility submissions. Flared or vented gas at a host facility would have to be allocated back to the lease	Note—The proposed rule did not have a § 250.1163(a)(3), this comment presumably refers to § 250.1163(b)(3). The MMS agrees that modified reporting on Form MMS-4054 Part B (OGOR-B) is required in order to implement this GAO recommendation. In order to implement this, § 250.1163(a)(1) of the final rule will require operators to notify MMS of all facilities that process more than 2,000 bopd and therefore require meters. The Regional Supervisor will then establish Facility Measurement Point (FMP) numbers for those metering locations. These FMP numbers will be used on the OGOR-B forms to identify the facilities where flaring and venting occurs. Further, in order to ease the reporting burden, the language will be modified from that in the proposed rule. Instead of requiring operators to associate all flared and vented volumes with the facilities where the flaring and venting occurred, such reporting (on OGOR-B forms) is only required for those facilities which are required to install flare/vent meters (§ 250.1160(b)(3)). For other facilities, operators must continue to report flared and vented volumes by lease or unit (§ 250.1163(b)(4)) (note that flared and vented volumes must be separated regardless of whether reporting is by facility, lease, or unit). Additionally, MRM will send guidance to operators on all other reporting requirements necessitated by this regulatory change.
§ 250.1163(b)(1)—Reporting separate flaring or venting on OGOR B will require modification to current reporting requirements	See response § 250.1163(a)(3).
§ 250.1163(b)(2)—Lease use already reported on OGOR B	The MMS agrees. Section 250.1163(b)(2) requires reporting lease use gas on Form MMS-4054, which is the OGOR. This rule does not impose additional lease use reporting requirements. The wording was modified slightly to clarify this issue.
§ 250.1163(b)(3)—Reporting flaring or venting from multiple facilities separately on a single lease is redundant and requires changes from industry and MRM. These records are kept at each facility and could be requested from the operator as needed to eliminate this burdensome requirement	See response § 250.1163(a)(3).
§ 250.1163(c)—Industry sends a letter summarizing pertinent flaring or venting information after receiving oral approval to flare or vent; requiring actual flaring or venting records be kept on location is redundant	The MMS disagrees. Summary information submitted in a letter following an oral approval is only a portion of the required records to be saved on location. A complete record must be maintained on each facility for routine inspections by MMS personnel.
§ 250.1164(b)(1)—Subpart C is sufficient to regulate pollution issues	The MMS agrees. This paragraph was deleted.
§ 250.1167-General—Requiring the following additional information is burdensome and redundant to data previously submitted in other documents (e.g. CIDs)	Data submitted for an early application would often be obsolete interpretations and result in inaccurate conclusions. Furthermore, receiving the data in separate submittals will expedite MMS review of industry applications.
§ 250.1167(a)(3)—net sand isopach
§ 250.1167(a)(4)—net hydrocarbon isopach
§ 250.1167(b)(2)—amplitude maps
§ 250.1167(d)(1)—estimated recoverable reserves for each completion in a reservoir
§ 250.1167(e)(2)—reservoir name and whether it is competitive

After reviewing and responding to the comments, MMS changed the appropriate rule language as specified in the MMS comment response. Table 3 compares the changes from the NPR to this final rule.

Final Rule Organization

The final rule completely restructures subpart K. The final rule is divided into shorter, easier-to-read sections, that focus on only one topic. For example, in the current subpart K regulation, the requirements regarding burning liquid hydrocarbons, as well as those governing flaring or venting natural gas, were all together in one section. In the final rule, these same requirements are in five sections, making it easier for an operator to find the information that applies to a particular situation. The numbering for subpart K starts at § 250.1150 instead of § 250.1100 to accommodate other planned rulemaking. The final rule structure is shown in the following table:

Current regulations	Final rule
§ 250.1100 Definitions for production rates	§ 250.105 Definitions.
§ 250.105 Definitions
§ 250.1101 General requirements and classification of reservoirs	§ 250.1150 What are the general reservoir production requirements?
	§ 250.1154 How do I determine if my reservoir is sensitive?
	§ 250.1155 What information must I submit for sensitive reservoirs?
	§ 250.1156 What steps must I take to receive approval to produce within 500 feet of a unit or lease line?
	§ 250.1157 How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap?
§ 250.1102 Oil and gas production rates	Requirements for production rates are largely eliminated. Portions retained were combined with new information.
	§ 250.1159 May the Regional Supervisor limit my well or reservoir production rates?
§ 250.1103 Well production testing	§ 250.1151 How often must I conduct well production tests?
	§ 250.1152 How do I conduct well tests?
§ 250.1104 Bottomhole pressure survey	§ 250.1153 When must I conduct a static bottomhole pressure survey?
§ 250.1105 Flaring or venting of gas and burning liquid hydrocarbons	§ 250.1160 When may I flare or vent gas?
	§ 250.1161 When may I flare or vent gas for extended periods of time?
	§ 250.1162 When may I burn produced liquid hydrocarbons?
	§ 250.1163 How must I measure gas flaring or venting volumes and liquid hydrocarbon burning volumes and what records must I maintain?
Start Printed Page 20284
	§ 250.1164 What are the requirements for flaring or venting gas containing H₂ S?
§ 250.1106 Downhole commingling	§ 250.1158 How do I receive approval to downhole commingle hydrocarbons?
§ 250.1107 Enhanced oil and gas recovery operations	§ 250.1165 What must I do for enhanced recovery operations?
New	§ 250.1159 May the Regional Supervisor limit my well or reservoir production rates?
	§ 250.1166 What additional reporting is required for developments in the Alaska OCS Region?
	§ 250.1167 What information must I submit with forms and for approvals?

Procedural Matters

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

The Office of Management and Budget (OMB) has designated this rule significant for OMB review under Executive Order 12866.

(1) The final rule will not have an annual effect of $100 million or more on the economy. It will 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 final 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 previous requirements will be relaxed. For example, limits on production rates were eliminated in most cases. This will allow the operators to produce the oil and gas at the rates that they determine are best, and will not have a significant effect on any sector of the economy.

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

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

(4) This final rule will raise novel legal or policy issues.

Regulatory Flexibility Act

The Department of the Interior certifies that this final rule will not have a significant economic effect on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.).

The changes in this rule will affect lessees and operators of leases in the OCS. This includes about 130 active Federal oil and gas lessees. Small lessees that operate under this rule fall under the Small Business Administration's (SBA) North American Industry Classification System (NAICS) codes 211111, Crude Petroleum and Natural Gas Extraction, and 213111, Drilling Oil and Gas Wells. For these NAICS code classifications, a small company is one with fewer than 500 employees. Based on these criteria, an estimated 70 percent of these companies are considered small. This final rule, therefore, will affect a substantial number of small entities, but the changes in the rule will not have a significant economic effect on a these entities.

The only new requirement that will 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. The MMS agrees with this recommendation. The MMS regulations allow flaring and venting in very limited circumstances. These meters will 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 will not produce an undue burden on small companies, it is limited to those facilities that process more than an average of 2,000 bopd.

In the proposed rule, MMS estimated that 34 companies will have to install meters on 112 facilities at an average cost of $77,000 per facility, with a total cost to industry of $8,624,000 (112 × $77,000 = $8,624,000). Of those 34 companies, nine companies are considered small entities, based on the NAICS. These nine companies represent only 7 percent of the 130 operators in the OCS. We estimate that seven of these nine companies will need to install meters on one facility each; one company will need to install meters on two facilities; and one company will need to install meters on three facilities. This represents an average cost of $102,667 for each of the small companies (12 facilities × $77,000/9 companies). For the remaining companies, the average cost to install meters will be $308,000 per company (100 facilities × $77,000/25 companies). 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. Allegations of discrimination/retaliation filed with the SBA will be investigated for appropriate action.

Small Business Regulatory Enforcement Fairness Act

The final rule is not a major rule under 5 U.S.C. 804(2) of the Small Business Regulatory Enforcement Fairness Act. This final rule:

a. Will not have an annual effect on the economy of $100 million or more. Start Printed Page 20285This final rule revises the requirements for oil and gas production. Most of the new requirements are paperwork requirements, and will not add significant time to development and production processes. One new requirement will add new costs for some operators. Operators will be required to install flare/vent meters on any facility that processes more than an average of 2,000 bopd. The MMS estimates that 34 companies will have to install meters on 112 facilities at an average cost of $77,000 per facility, with a total cost to industry of $8,624,000 (112 × $77,000 = $8,624,000).

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

The only change to this rule that has a cost associated with it is a new requirement to install meters on facilities that process more than an average of 2,000 bopd. As discussed previously, this requirement will not significantly increase the cost of doing business offshore and will not cause an increase in costs or prices for consumers, individual industries, Federal, State, or local government agencies, or geographic regions.

c. Will 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 final rule will 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 will encourage conservation of our natural resources.

Unfunded Mandates Reform Act

This final rule will not impose an unfunded mandate on State, local, or tribal governments or the private sector of more than $100 million per year. The final rule will not have a significant or unique effect on State, local, or tribal governments or the private sector. A statement containing the information required by the Unfunded Mandates Reform Act (2 U.S.C. 1531 et seq.) is not required.

Takings Implication Assessment (E.O. 12630)

Under the criteria in E.O. 12630, this final rule does not have significant takings implications. The final rule is not a governmental action capable of interference with constitutionally protected property rights. A Takings Implication Assessment is not required.

Federalism (E.O. 13132)

Under the criteria in E.O. 13132, this final rule does not have federalism implications. This final rule will 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 final rule will not affect that role. A Federalism Assessment is not required.

Civil Justice Reform (E.O. 12988)

This rule complies with the requirements of E.O. 12988. Specifically, this rule:

(a) Meets the criteria of section 3(a) requiring that all regulations be reviewed to eliminate errors and ambiguity and be written to minimize litigation; and

(b) Meets the criteria of section 3(b)(2) requiring that all regulations be written in clear language and contain clear legal standards.

Consultation With Indian Tribes (E.O. 13175)

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

Paperwork Reduction Act (PRA)

This rulemaking is a total rewrite of regulations under 30 CFR Part 250, Subpart K, Oil and Gas Production Rates. The rule changes the information collection (IC) burden already approved for current subpart K regulations; therefore, a submission was made to OMB under 44 U.S.C. 3501 et seq. The OMB approved the collection of information under OMB Control Number 1010-0041, expiration date 3/31/2013, for a total of 43,396 burden hours and $9,234,392 non-hour cost burdens.

The title of the collection of information for the rule is 30 CFR Part 250, Subpart K, Oil and Gas Production Requirements. Potential respondents comprise Federal oil and gas and sulphur lessees. Responses to this collection are mandatory or are required to obtain or retain a benefit. 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 does not include questions of a sensitive nature. The 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 250.197, Data and information to be made available to the public or for limited inspection, 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 information collected under subpart K is used in our efforts to conserve natural resources, prevent waste, and protect correlative rights, including the Government's royalty interest. Specifically, MMS uses the information to:

Evaluate requests to burn liquid hydrocarbons and vent and flare gas to ensure that these requests are appropriate;
Determine if a maximum production or efficient rate is required; and,
Review applications for downhole commingling to ensure that action maximizes ultimate recovery.

The IC burdens for these regulations include several changes from the burdens published in the preamble to the proposed rule. The changes and reasons for making them are:

(1) On August 25, 2008 (73 FR 49943) a final rulemaking was published that increased the cost recovery fees required under § 250.125. These fees became effective on September 24, 2008, and the final rule includes these fees that affect subpart K.

(2) The OMB approval of the information collection burden (1010-0041) for the current subpart K regulations was due to expire before these final regulations became effective. As required by the Paperwork Reduction Act, to renew the OMB approval of 1010-0041, we consulted with several respondents and adjusted the burden estimates and number of responses accordingly. The burden estimates for the final rule reflect these updates.

(3) Based on a public comment, we removed the requirements published in proposed § 250.1164(b)(1) to request Regional Supervisor approval for emitting more than 15 pounds of SO₂, and § 250.1164(b)(2), submit to the Regional Supervisor air quality modeling analysis. The commenter stated that 30 CFR 250, subpart C, was sufficient to regulate pollution issues and MMS agreed.

(4) We also added two IC requirements and burdens to the following IC burden table for the final regulations.

(a) First, operators/lessees must provide notice to operator(s) of adjacent property(ies) of their request for MMS approval to produce within 500 feet of a unit or lease line or to commingle Start Printed Page 20286hydrocarbons. Sections 250.1156(b) and 250.1158(b) allow the notified party(ies) to submit letters of acceptance or objection to MMS. This provision was in the proposed rule, but was inadvertently omitted from the IC table in the proposed rule.

(b) Second, is a new paragraph (1) under § 250.1163(a) that requires a notice to MMS when a facility begins to process more than an average of 2,000 BOPD per month. This change was made in response to a commenter's concern that the current Oil and Gas Operations Report (OGOR)-B form does not allow for multiple facility submissions.

30 CFR part 250 subpart K	Reporting & recordkeeping requirement	Non-hour cost burdens
30 CFR part 250 subpart K	Reporting & recordkeeping requirement	Hour burden	Average number of annual responses	Annual burden hours
WELL TESTS/SURVEYS and CLASSIFYING RESERVOIRS
1151(a)(1), (c); 1167	Conduct well production test; submit Form MMS-126 (Well Potential Test Report) and supporting information (within 15 days after end of test period)	3	1,325 forms	3,975
1151(a)(2), (c); 1167	Conduct well production test; submit Form MMS-128 (Semiannual Well Test Report) and supporting information (within 45 days after end of calendar half-year)	0.1 to 3 *	13,000 GOM forms 600 POCS forms.	3,100
1151(b)	Request extension of time to submit results of semi-annual well test	0.5	37 requests	19
1152(b), (c)	Request approval to conduct well testing using alternative procedures	0.5	37 requests	19
1152(d)	Provide advance notice of time and date of well tests	0.5	10 notices	5
1153	Conduct static bottomhole pressure survey; submit Form MMS-140 (Bottomhole Pressure Survey Report) (within 60 days after survey)	14	1,270 surveys	17,780
1153(d)	Submit a letter, along with Form MMS-140, to request a departure from requirement to run a static bottomhole survey	1	120 survey departures	120
1154; 1167	Request approval, along with supporting information, to reclassify reservoir	6	20 requests	120
1155; 1165(b); 1166(c); 1167	Submit Form MMS-127 (Sensitive Reservoir Information Report) and supporting information (within 45 days after certain events or at least annually)	2.2	2,189 forms	4,816
Subtotal			18,608 responses	29,954 hours
APPROVALS PRIOR TO PRODUCTION
1156; 1167	Request approval to produce within 500 feet of a unit or lease line; submit supporting information; pay service fee and include pay.gov payment confirmation with request; notify adjacent operators and provide MMS proof of notice date.	5	33 requests	165
		$3,608 × 33 requests = $119,064
1156(b); 1158(b)	Notify adjacent operators submit letters of acceptance or objection to MMS within 30 days after notice	.5	33 letters	17 (rounded)
1157; 1167	Request approval to produce gas-cap gas in an oil reservoir with an associated gas cap, or to continue producing an oil well showing characteristics of a gas well with an associated gas cap; submit supporting information; pay service fee and include pay.gov payment confirmation with request.	12	51 requests	612
		$4,592 × 51 requests = $234,192
Start Printed Page 20287
1158; 1167	Request approval to downhole commingle hydrocarbons; submit supporting information; pay service fee and include pay.gov payment confirmation with request; notify operators and provide proof of notice date.	6	48 applications	288
		$5,357 × 48 applications = $257,136
			165 responses	1,082 hours
Subtotal			$610,392 non-hour costs
FLARING, VENTING, and BURNING HYDROCARBONS
1160; 1161; 1163(e)	Request approval to flare or vent natural gas or exceed specified volumes; submit documentation; report flare/vent information due to blow down of transportation pipelines within 72 hours after incident	0.5	1,007 requests/ reports.	504
1162; 1163(e)	Request approval to burn produced liquid hydrocarbons; submit documentation	0.5	60 requests/ reports.	30
1163(a)	One-time initial purchase and installation of gas meters to measure and record the amount of gas flared or vented. This is a non-hour cost burden required to comply with revised regulations with relatively small or no burden in subsequent years	112 meters × $77,000 ea = $8,624,000
1163(a)(1)	Notify MMS when facility begins to process more than an average of 2,000 bopd per month	0.833	112 notices	93 (rounded)
1163(b); 1164(c)	Report to MRM hydrocarbons produced, including measured gas flared/vented and liquid hydrocarbon burned—burden covered under 1010-0139.			0
1163(c), (d)	Maintain records for 6 years detailing gas flaring/venting, liquid hydrocarbon burning; and flare/vent meter recordings; make available for inspection or provide copies upon request	13	869 flare/vent platforms.	11,297
		0.5	60 liquid hydrocarbons	30
1164(c)	Submit monthly reports of flared or vented gas containing H₂ S	2	3 operators × 12 mos. = 36	72
1160(b); 1164(b)(1), (2)	H₂ S Contingency, Exploration, or Development and Production Plans and, Development Operations Coordination Documents—burdens covered under 1010-0141 and 1010-0151. Monitor air quality and report—burdens covered under 1010-0057.			0
			2,084 responses	12,026 hours
Subtotal			$8,624,000 non-hour costs
OTHER REQUIREMENTS
1165	Submit proposed plan and supporting information for enhanced recovery operations; including Form MMS-127	12	14 plans	168
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
1166	Alaska Region only: submit annual reservoir management report and supporting information, including Form MMS-127	1	1 (req'd by State, MMS gets copy)	1
		100	1 new development not State lands	100
Start Printed Page 20288
		20	3 annual revisions	60
1150-1167	General departure or alternative compliance requests not specifically covered elsewhere in subpart K	1	5 submissions	5
Subtotal			24 responses	334 hours
			20,881 responses	43,396 hours
TOTAL BURDEN			$9,234,392 non-hour cost burdens
* 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.

An agency may not conduct or sponsor, and you are not required to respond to, a collection of information unless it displays a currently valid OMB control number. The public may comment, at any time, on the accuracy of the IC burden in this rule and may submit any comments to the Department of the Interior; Minerals Management Service; Attention: Regulations and Standards Branch; Mail Stop 5438; 381 Elden Street; Herndon, Virginia 20170-4817.

National Environmental Policy Act of 1969

This rule does not constitute a major Federal action significantly affecting the quality of the human environment. A detailed statement under the National Environmental Policy Act of 1969 is not required because the rule is covered by a categorical exclusion. This rule is excluded from the requirement to prepare a detailed statement because it falls within the MMS categorical exclusion covering the “[i]ssuance and modification of regulations, Orders, Standards, Notices to Lessees and Operators. Guidelines and field rules for which the impacts are limited to administrative, economic, or technological effects and the environmental impacts are minimal.” This categorical exclusion is documented in 516 Departmental Manual 15.4(C)(1). We have also determined that the rule does not involve any of the extraordinary circumstances listed in 43 CFR 46.215 that would require further analysis under the National Environmental Policy Act.

Data Quality Act

In developing this rule, we did not conduct or use a study, experiment, or survey requiring peer review under the Data Quality Act (Pub. L. 106-554, app. C § 515, 114 Stat. 2763, 2763A-153-154).

Effects on the Energy Supply (E.O. 13211)

This rule is not a significant energy action under the definition in E.O. 13211. A Statement of Energy Effects is not required.

List of Subjects in 30 CFR Part 250

Continental shelf
Environmental protection
Oil and gas exploration
Public lands—mineral resources, reporting and recordkeeping requirements

Dated: December 23, 2009.

Ned Farquhar,

Acting Assistant Secretary—Land and Minerals Management.

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

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

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

Authority: 31 U.S.C. 9701, 43 U.S.C. 1334.

2. Amend § 250.105 by revising the definition of Sensitive reservoir and adding in alphabetical order definitions for Flaring and Venting to read as follows:

§ 250.105

Definitions.

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

Sensitive reservoir means a reservoir in which the production rate will affect 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 paragraphs (a)(27) through (29) to read as follows:

§ 250.125

Service fees.

(a) * * *

Service Fee Table
Service—processing of the following:	Fee amount	30 CFR citation


* * * * * * *
(27) 500 Feet From Lease/Unit Line Production Request	3,608	§ 250.1156(a).
(28) Gas Cap Production Request	4,592	§ 250.1157.
(29) Downhole Commingling Request	5,357	§ 250.1158(a).

* * * * * * *

4. In § 250.199, paragraph (e)(10) is revised to read as follows:

§ 250.199

Paperwork Reduction Act statements—information collection.

(e) * * *

30 CFR subpart, title and/or MMS Form (OMB Control No.)	Reasons for collecting information and how used

* * * * * * *
(10) Subpart K, Oil and Gas Production Rates (1010-0041), including Forms MMS-126, Well Potential Test Report; MMS-127, Sensitive Reservoir Information Report; MMS-128, Semiannual Well Test Report; MMS-140 Bottomhole Pressure Survey Report	To inform MMS of production rates for hydrocarbons produced on the OCS. To ensure economic maximization of ultimate hydrocarbon recovery.

* * * * * * *

§ 250.490

[Amended]

5. In § 250.490, paragraph (o)(3), the citation “§ 250.1105” is revised to read “§ 250.1164”.

6. Revise subpart K to read as follows:

Subpart K—Oil and Gas Production Requirements

General

250.1150: What are the general reservoir production requirements?
250.1151: How often must I conduct well production tests?
250.1152: How do I conduct well tests?
250.1153: When must I conduct a static bottomhole pressure survey?
250.1154: How do I determine if my reservoir is sensitive?
250.1155: What information must I submit for sensitive reservoirs?
250.1156: What steps must I take to receive approval to produce within 500 feet of a unit or lease line?
250.1157: How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap?
250.1158: How do I receive approval to downhole commingle hydrocarbons?
250.1159: May the Regional Supervisor limit my well or reservoir production rates?
250.1160: When may I flare or vent gas?
250.1161: When may I flare or vent gas for extended periods of time?
250.1162: When may I burn produced liquid hydrocarbons?
250.1163: How must I measure gas flaring or venting volumes and liquid hydrocarbon burning volumes, and what records must I maintain?
250.1164: What are the requirements for flaring or venting gas containing H₂ S?
250.1165: What must I do for enhanced recovery operations?
250.1166: What additional reporting is required for developments in the Alaska OCS Region?
250.1167: What information must I submit with forms and for approvals?

General

§ 250.1150

What are the general reservoir production requirements?

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

Well Tests and Surveys

§ 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 to the Regional Supervisor an original and two copies of the appropriate form required by paragraph (a) of this section; one of the copies of the form must be a public information copy in accordance with §§ 250.186 and 250.197, and marked “Public Information.” You must submit two copies of the supporting information as listed in the table in § 250.1167 with form MMS-126.

§ 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 a 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); andStart Printed Page 20290

(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. To request a departure, you must submit a justification, along with Form MMS-140, Bottomhole Pressure Survey Report, showing a calculated bottomhole pressure or any measured data.

Classifying Reservoirs

§ 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 enhanced recovery.

(b) For the purposes of this subpart, near-critical fluids are:

(1) Those fluids that occur in high temperature, high-pressure reservoirs where it is not possible to define the liquid-gas contact; or

(2) Fluids in reservoirs that are near bubble point or dew point conditions.

(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 to the Regional Supervisor an original and two copies of Form MMS-127; one of the copies must be a public information copy in accordance with §§ 250.186 and 250.197, and marked “Public Information.” You must also submit two copies of the supporting information, as listed in the table in § 250.1167. 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, but you do not need to resubmit unrevised structure maps (§ 250.1167(a)(2)) or previously submitted well logs (§ 250.1167(c)(1));

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

Approvals Prior to Production

§ 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 reservoir within 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, according to the instructions in § 250.126, and the supporting information, as listed in the table in § 250.1167, with your request. The Regional Supervisor will determine whether approval of your request will maximize ultimate recovery, avoid the waste of natural resources, or protect correlative rights. You do not need to obtain approval if the adjacent leases or units have the same unit, lease (record title and operating rights), 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 referenced 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-cap gas from an oil reservoir with an associated gas cap?

(a) You must request and receive approval from the Regional Supervisor:

(1) Before producing gas-cap gas from each completion in an oil reservoir that is known to have an associated gas cap.Start Printed Page 20291

(2) To continue production from a well if the oil reservoir is not initially known to have an associated gas cap, but the oil well begins to show characteristics of a gas well.

(b) For either request, you must submit the service fee listed in § 250.125, according to the instructions in § 250.126, 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. You must include the service fee listed in § 250.125, according to the instructions in § 250.126, and the supporting information, as listed in the table in § 250.1167, with your request.

(b) If one or more of the reservoirs proposed for commingling 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

§ 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 and/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

§ 250.1160

When may I flare or vent gas?

(a) You must request and receive approval from the Regional Supervisor to flare or vent natural 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 H₂ 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 unloading or cleaning or 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 of 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, during 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) Regardless of the requirements in paragraph (a) of this section, you must not flare or vent gas over the volume approved in your Development Operations Coordination Document (DOCD) or your Development and Production Plan (DPP).

(c) The Regional Supervisor may establish alternative approval procedures to cover situations when 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) 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.

(f) Fugitive emissions from valves, fittings, flanges, pressure relief valves or similar components do not require approval under this subpart unless specifically required by the Regional Supervisor.

§ 250.1161

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

You must request and receive approval from the Regional Supervisor to flare or vent gas for an extended period of time. The Regional Supervisor will specify the approved period of time, which will not exceed 1 year. The Regional Supervisor may deny your request if it does not ensure the conservation of natural resources or is not consistent with national interests relating to development and production of minerals of the OCS. The Regional Supervisor may approve your request for one of the following reasons:

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

(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.

§ 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 liquid hydrocarbons if you demonstrate that transporting them to market or re-injecting them is not technically feasible or poses a significant risk of harm to offshore personnel or the environment.

(b) 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 May 2010, you must install flare/vent meters within 180 days after May 2010. If your facility processes more than an average of 2,000 bopd during a calendar month after May 2010, you must install flare/vent meters within 120 days after the end of the month in which the average amount of oil processed exceeds 2,000 bopd.

(1) You must notify the Regional Supervisor when your facility begins to process more than an average of 2,000 bopd in a calendar month;

(2) The flare/vent meters must measure all flared and vented gas within 5 percent accuracy;

(3) You must calibrate the meters regularly, in accordance with the manufacturer's recommendation, or at least once every year, whichever is shorter; and

(4) You must use and maintain the flare/vent meters for the life of the facility.

(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 § 210.102 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 lease, such as gas used to power engines, instrument gas, and gas used to maintain pilot lights, as lease use gas.

(3) If flare/vent meters are required at one or more of your facilities, you must report the amount of gas flared and vented at each of those facilities separately from those facilities that do not require meters and separately from other facilities with meters.

(4) If flare/vent meters are not required at your facility:

(i) You may report the gas flared and vented on a lease or unit basis. Gas flared and vented from multiple facilities on a single lease or unit may be reported together.

(ii) If you choose to install meters, you may report the gas volume flared and vented according to the method specified in paragraph (b)(3) of this section.

(c) You must prepare and maintain records detailing gas flaring, gas venting, and liquid hydrocarbon burning for each facility for 6 years.

(1) You must maintain these records on the facility for at least the first 2 years and have them available for inspection by MMS representatives.

(2) 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 are not required to keep them on the facility.

(3) The records must include, at a minimum:

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

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

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

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

(v) Documentation of all required approvals.

(d) If your facility is required to have flare/vent meters:

(1) You must maintain the meter recordings for 6 years.

(i) You must keep these recordings on the facility for 2 years and have them available for inspection by MMS representatives.

(ii) 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.

(iii) These recordings must include the begin times, end times, and volumes for all flaring and venting incidents.

(2) You must maintain flare/vent meter calibration and maintenance records on the facility for 2 years.Start Printed Page 20293

(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.

§ 250.1164

What are the requirements for flaring or venting gas containing H₂ S?

(a) You may not vent gas containing H₂ S, except for minor releases during maintenance and repair activities that do not result in a 15-minute time-weighted average atmosphere concentration of H₂ S of 20 ppm or higher anywhere on the platform.

(b) You may flare gas containing H₂ S only if you meet the requirements of §§ 250.1160, 250.1161, 250.1163, and the following additional requirements:

(1) For safety or air pollution prevention purposes, the Regional Supervisor may further restrict the flaring of gas containing H₂ S. The Regional Supervisor will use information provided in the lessee's H₂ S Contingency Plan (§ 250.490(f)), Exploration Plan, DPP, DOCD, and associated documents to determine the need for restrictions; and

(2) 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, under § 250.303, 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) The Regional Supervisor may require you to submit monthly reports of flared and vented gas containing H₂ S. Each report must contain, on a daily basis:

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

(2) H₂ S concentration in the flared or vented gas; and

(3) The calculated amount of SO₂ emitted.

Other Requirements

§ 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 an increase in 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 geologic and engineering overview, Form MMS-127 and supporting data as required in § 250.1167, 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 § 210.102 of this title.

§ 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:

(1) Provide for the prevention of waste;

(2) Provide for the protection of correlative rights; and

(3) Maximize ultimate recovery of oil and gas.

(b) If your development is jointly regulated by MMS and the State of Alaska, MMS and the Alaska Oil and Gas Conservation Commission 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.

§ 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 identified in columns 1 and 2 and for the approvals required under this subpart identified in columns 3 through 6:

	WPT MMS-126 (2 copies)	SRI MMS-127 (2 copies)	Gas cap production	Downhole commingling	Reservoir reclassification	Production within 500-ft of a unit or lease line
(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) 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:
Start Printed Page 20294
(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) Geologic overview of project			√	√	√	√
(5) Explanation of why the proposed completion scenario will maximize ultimate recovery			√	√		√
(6) List of all wells in subject reservoirs that have ever produced or been used for injection			√	√	√	√
√ Required.
† Each Gas Cap Production request and Downhole Commingling request must 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. The Regional Supervisor may waive submittal of some of the required data on a case-by-case basis.

(f) Depending on the type of approval requested, you must submit the appropriate payment of the service fee(s) listed in § 250.125, according to the instructions in § 250.126.

[FR Doc. 2010-8798 Filed 4-16-10; 8:45 am]

BILLING CODE 4310-MR-P

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Document Information

Published:: 04/19/2010
Department:: Minerals Management Service
Entry Type:: Rule
Action:: Final rule.
Document Number:: 2010-8798
Pages:: 20271-20294 (24 pages)
Docket Numbers:: MMS-2008-OMM-0034
RINs:: 1010-AD12: Oil and Gas Production Rates
RIN Links:: https://www.federalregister.gov/regulations/1010-AD12/oil-and-gas-production-rates
Topics:: Continental shelf, Environmental protection, Oil and gas exploration, Public lands-mineral resources, Reporting and recordkeeping requirements
PDF File:: 2010-8798.pdf
CFR: (22): 30 CFR 250.105; 30 CFR 250.125; 30 CFR 250.199; 30 CFR 250.490; 30 CFR 250.1150; More ...