[Federal Register Volume 72, Number 43 (Tuesday, March 6, 2007)]
[Proposed Rules]
[Pages 9884-9901]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E7-3846]


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DEPARTMENT OF THE INTERIOR

Minerals Management Service

30 CFR Part 250

RIN 1010-AD12


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

AGENCY: Minerals Management Service (MMS), Interior.

ACTION: Proposed rule.

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

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

ADDRESSES: You may submit comments on the rulemaking by any of the 
following methods. Please use the Regulation Identifier Number (RIN) 
1010-AD12 as an identifier in your message. See also Public Comment 
Procedures under Procedural Matters.
    <bullet> MMS's Public Connect on-line commenting system, https://ocsconnect.mms.gov. Follow the instructions on the Web site for 
submitting comments.
    <bullet> Federal eRulemaking Portal: http://www.regulations.gov. 
Follow the instructions on the Web site for submitting comments.
    <bullet> E-mail MMS at <a href="/cdn-cgi/l/email-protection#fc8e8990998fd29f9391919992888fbc91918fd29b938a"><span class="__cf_email__" data-cfemail="aedcdbc2cbdd80cdc1c3c3cbc0daddeec3c3dd80c9c1d8">[email protected]</span></a>. Use RIN 1010-AD12 in 
the subject line.

[[Page 9885]]

    <bullet> Fax: 703-787-1546. Identify with the RIN, 1010-AD12.
    <bullet> Mail or hand-carry comments to the Department of the 
Interior; Minerals Management Service; Attention: Rules Processing Team 
(RPT); 381 Elden Street, MS-4024; Herndon, Virginia 20170-4817. Please 
reference ``Oil and Gas Production Requirements, 1010-AD12'' in your 
comments and include your name and return address.
    <bullet> Send comments on the information collection in this rule 
to: Interior Desk Officer 1010-AD12, Office of Management and Budget; 
202/395-6566 (facsimile); e-mail: <a href="/cdn-cgi/l/email-protection#dab5b3a8bb85beb5b9b1bfae9ab5b7b8f4bfb5aaf4bdb5ac"><span class="__cf_email__" data-cfemail="224d4b50437d464d41494756624d4f400c474d520c454d54">[email protected]</span></a>.

FOR FURTHER INFORMATION CONTACT: Amy C. White, Regulations and 
Standards Branch, 703-787-1665.

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

GAO Report

    In July 2004, the GAO issued a report on world-wide emissions from 
vented and flared natural gas titled, ``Natural Gas Flaring and 
Venting--Opportunities to Improve Data and Reduce Emissions'' (GAO-04-
809). This report is available on the GAO Web site at: http://www.gao.gov/new.items/d04809.pdf. This report reviewed the flaring and 
venting data available, the extent of flaring and venting, their 
contributions to greenhouse gas emissions, and opportunities for the 
federal government to reduce flaring and venting. The report found 
that:
    <bullet> The amount of gas emitted through flaring and venting 
worldwide is small compared with global natural gas production and 
represents a small portion of greenhouse gas emissions.
    <bullet> Worldwide flaring and venting is estimated to contribute, 
respectively, about 4 percent of the total methane and about 1 percent 
of the total carbon dioxide emissions caused by human activity.
    <bullet> EIA [Energy Information Administration] estimates that the 
United States flares or vents about 0.4 percent of its production, 
representing only 3 percent of the world's total amount of natural gas 
flared and vented.
    <bullet> In the United States, there are well-developed natural gas 
markets and infrastructure to reduce the flaring and venting of 
associated natural gas.
    <bullet> Since 1990, the quantity of oil produced has increased, 
but because of various global reduction initiatives, the quantity of 
natural gas flared and vented has remained constant. Consequently, 
natural gas emissions as a percentage of oil production have decreased.
    <bullet> Since the impact of methane (venting) on the earth's 
atmosphere is about 23 times greater than that of carbon dioxide 
(flaring), a small change in the ratio of flaring to venting could 
cause a disproportionate change in the impact of emissions.
    The report concluded that more accurate records on flaring and 
venting are needed to determine the amount of the resource that is lost 
and the volume of greenhouse gas emissions these practices contribute 
to the atmosphere each year. The GAO made two recommendations to the 
Secretary of the Interior: (1) ``Consider the cost and benefit of 
requiring that companies flare the natural gas, whenever possible, when 
flaring or venting is necessary,'' and (2) ``consider the cost and 
benefit of requiring that companies use flaring and venting meters to 
improve oversight.'' In addition, there was a recommendation to the 
Secretary of Energy to consider, ``in consultation with EPA 
[Environmental Protection Agency], MMS, and BLM [Bureau of Land 
Management], how to best collect separate statistics on flaring and 
venting.''
    In comments on the draft report, the Department of the Interior 
(DOI) concurred with the report's recommendations and agreed to assess 
the cost effectiveness of requiring the oil and gas industry to 
implement these changes. MMS conducted analyses to assess the costs and 
benefits of requiring flare/vent meters and also of requiring flaring 
instead of venting. The first analysis supported the recommendation to 
require meters provided that the facilities process more than 2,000 
barrels of oil per day (BOPD). This requirement is included in the 
proposed rule.
    The second analysis indicated that a regulatory change to require 
flaring instead of venting may be appropriate. However, the cost of 
implementing this requirement is significant, and input from 
potentially affected parties is necessary to establish a reasonable 
threshold. MMS plans to work directly with interested parties to 
determine the best approach in considering the GAO recommendation to 
require flaring instead of venting natural gas. We are soliciting 
comments on this issue in this proposed rule. We would like comments 
related to additional costs, environmental impacts, and conditions or 
situations where flaring may not be advisable. We are planning a 
workshop to discuss the issue. The workshop would be followed by 
appropriate rulemaking.
    To improve data collection, as the GAO report suggested, MMS is 
proposing that operators report flaring and venting volumes to MMS 
separately. Currently, MMS only collects information on the total 
natural gas flared and vented. Operators do not need to differentiate 
between the two categories. In addition, MMS inspectors currently use 
infrared cameras to verify natural gas venting.

Proposed Rule

Organization

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

------------------------------------------------------------------------
              Current rule                        Proposed rule
------------------------------------------------------------------------
Sec.   250.1100 Definitions for          Sec.   250.105 Definitions.
 production rates.
Sec.   250.105 Definitions.
Sec.   250.1101 General requirements     Sec.   250.1150 General
 and classification of reservoirs.        reservoir production
                                          requirements.
                                         Sec.   250.1154 How do I
                                          determine if my reservoir is
                                          sensitive?
                                         Sec.   250.1155 What
                                          information must I submit for
                                          sensitive reservoirs?

[[Page 9886]]

 
                                         Sec.   250.1156 What steps must
                                          I take to receive approval to
                                          produce within 500 feet of a
                                          unit or lease line?
                                         Sec.   250.1157 How do I
                                          receive approval to produce
                                          gas from an oil reservoir with
                                          an associated gas cap?
Sec.   250.1102 Oil and gas production   Requirements for production
 rates.                                   rates are largely eliminated.
                                          Portions retained were
                                          combined with new information
                                          in ``Sec.   250.1159 May the
                                          Regional Supervisor limit my
                                          well or reservoir production
                                          rates?''
Sec.   250.1103 Well production testing  Sec.   250.1151 How often must
                                          I conduct well production
                                          tests?
                                         Sec.   250.1152 How do I
                                          conduct well tests?
Sec.   250.1104 Bottomhole pressure      Sec.   250.1153 When must I
 survey.                                  conduct a static bottomhole
                                          pressure survey?
Sec.   250.1105 Flaring or venting of    Sec.   250.1160 When may I
 gas and burning liquid hydrocarbons.     flare or vent gas?
                                         Sec.   250.1161 When may I
                                          flare or vent gas for extended
                                          periods of time?
                                         Sec.   250.1162 When may I burn
                                          produced liquid hydrocarbons?
                                         Sec.   250.1163 How must I
                                          measure gas flaring or venting
                                          and liquid hydrocarbon burning
                                          volumes and what records must
                                          I maintain?
                                         Sec.   250.1164 What are the
                                          requirements for flaring or
                                          venting gas containing H2S?
Sec.   250.1106 Downhole commingling...  Sec.   250.1158 How do I
                                          receive approval to downhole
                                          commingle hydrocarbons?
Sec.   250.1107 Enhanced oil and gas     Sec.   250.1165 What must I do
 recovery operations.                     for enhanced recovery
                                          operations?
New....................................  Sec.   250.1159 May the
                                          Regional Supervisor limit my
                                          well or reservoir production
                                          rates?
                                         Sec.   250.1166 What additional
                                          reporting is required for
                                          developments in the Alaska
                                          Region?
                                         Sec.   250.1167 What
                                          information must I submit for
                                          approvals?
------------------------------------------------------------------------

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

Major Changes to the Rule

    Some requirements from the previous edition of subpart K would be 
eliminated by the proposed rule because they are unnecessary in today's 
petroleum industry. For example, MMS required operators to establish 
maximum production rates (MPR's) for producing well completions, and 
maximum efficient rates (MER's) for producing reservoirs, in OCS Order 
No. 11 in 1974, during a period of oil shortages and energy crises. In 
1988, MMS reduced the MER requirement. Currently, MER's are required 
only on sensitive reservoirs (primarily oil reservoirs with associated 
gas caps). Determining and maintaining production rates imposes a 
significant burden on operators. Based on the past 30 years of 
experience, MMS has concluded that maximum rate requirements and 
production balancing requirements can be largely eliminated without 
significant detriment to efforts for conservation and maximization of 
ultimate recovery. However, the proposed rule would allow the Regional 
Supervisor to set production rates in cases where excessive production 
could harm ultimate recovery from the reservoir.
    The proposed rule would clarify required information submittals to 
MMS, including requirements relating to the documents submitted to MMS 
and the timing of those submissions. For example, there is additional 
guidance on notifying adjoining operators regarding production within 
500 feet of a common lease or unit line. The proposed rule would 
provide more detail as to when the notification must occur, what the 
notice must include, and how to verify the notification with MMS.
    The proposed rule would incorporate several Notices to Lessees and 
Operators (NTLs) that clarify the current regulations. These NTLs would 
be obsolete if the proposed rule becomes final and MMS would withdraw 
all of these NTLs at that time. However, if necessary, MMS would issue 
additional NTLs to provide guidance. The NTLs affected include:
    <bullet> NTL No. 97-16, ``Production Within 500 Feet of a Unit or 
Lease Line,'' effective August 1, 1997. This NTL clarifies MMS policy 
on issuing approvals for production within 500 feet of a unit or lease 
line, and includes details on what the requesting operator needs to 
provide to MMS for approval. Those details are addressed in the 
proposed rule.
    <bullet> NTL No. 98-23, ``Interim Reporting Requirements for 30 CFR 
250, subpart K, Oil and Gas Production Rates,'' effective October 15, 
1998. This NTL addressed oral approvals for gas flaring and relaxed 
some of the requirements regarding production rates, including MER and 
MPR in certain circumstances. The NTL clarified the submittal of 
written summary letters on flaring incidents that received oral 
approval. These requirements are addressed in the proposed rule.
    <bullet> NTL No. 99-G20, ``Downhole Commingling Applications,'' 
effective September 7, 1999. This NTL was issued in conjunction with 
NTL No. 99-G19. It clarifies what information the applicant needs to 
include in downhole commingling applications to ensure that the 
application is processed without delay. These information requirements 
were added to the proposed rule.
    <bullet> NTL No. 2006-N06, ``Flaring and Venting Approvals,'' 
effective December 19, 2006. This NTL clarifies the definitions of 
flaring and venting, the record-keeping requirements, the 
classification of emitted natural gas, and the MMS policy regarding 
continuous flaring or venting of small volumes of oil-well gas or gas-
well gas from storage vessels or other low-pressure production vessels 
when the gas cannot be economically recovered. These issues are 
addressed in the proposed rule. This NTL also provides contact 
information for each Region and provides sample

[[Page 9887]]

field records. These two items are not addressed in the proposed rule. 
MMS would issue a new NTL to include only this information, after we 
publish the final rule.
    The most significant change, with regard to cost, would be a 
proposed requirement for natural gas flare/vent meters on facilities 
that process significant volumes of oil. The current MMS requirements 
rely heavily on the accuracy of operator calculations and record 
keeping. Recent incidents have shown that these methods are 
insufficient to accurately capture actual flaring and venting volumes. 
The proposed rule would require the installation of meters to 
accurately measure all flared and vented natural gas on facilities that 
process more than 2,000 BOPD. These facilities have the potential to 
flare or vent significant volumes of associated gas.
    MMS estimates the cost of purchasing and installing these meters to 
be $77,000 per facility. Limiting the requirement to facilities that 
process over 2,000 BOPD ensures that the meters are a small expense 
relative to the cost of operating those facilities and relative to the 
income generated by those facilities; and that the requirement would 
not be an unfair burden to small operators. MMS estimates that 34 
operators would have to install the meters on 112 facilities. Of those 
operators that would have to install the meters, nine are considered 
small businesses, according to the North American Industry 
Classification System (NAICS).
    The July 2004 GAO report on world-wide emissions from vented and 
flared natural gas, discussed above, recommended that more accurate 
records on flaring and venting are needed to determine the amount of 
the resource that is wasted, and the volume of greenhouse gas these 
practices contribute to the atmosphere each year. The report 
recommended that DOI consider requiring flare/vent meters to measure 
the gas lost. MMS agrees with that recommendation. However, MMS 
believes installing these meters on facilities that process less than 
2,000 BOPD would not be cost effective, and might be an undue burden on 
smaller operators.
    MMS is also proposing to add new definitions for ``flaring'' and 
``venting'' to 30 CFR part 250 subpart A, and to revise the definition 
for ``sensitive reservoir.''
    The following is a brief section-by-section description of the 
substantive proposed changes to subpart K:
    Sec.  250.105 Definitions. In the current rule, definitions appear 
in subpart A at 30 CFR 250.105 and in subpart K at 30 CFR 250.1100. MMS 
proposes removing the definitions from subpart K because they already 
appear in subpart A.
General
    Sec.  250.1150 What are General Reservoir Production Requirements? 
Because the first section of subpart K would no longer contain the 
definitions, this section would contain the general requirements for 
producing wells and reservoirs.
Well Tests and Surveys
    Sec.  250.1151 How often must I conduct well production tests? Well 
production testing is required for all wells. This proposed section 
defines when an operator must perform the tests and describes the 
conditions for the tests. This section would cover well flow potential 
tests, semi-annual well tests, and any special tests that the Regional 
Supervisor may require. Operators would no longer be required to submit 
Semiannual Well Test Reports within 45 days of the tests. Instead, they 
would submit the reports within 45 days after the end of the calendar 
half-year. This would allow operators to submit all their well tests at 
one time and include the most recent tests for those few completions 
that produced during the 6-month period, but were not tested within the 
last 45 days.
    Sec.  250.1152 How do I conduct well tests? This proposed section 
describes how operators must conduct a well test. The testing 
procedures would be the same as in the current version of the rule. 
However, the section would be reformatted to make the procedures easier 
to follow. This reformatting would include the procedure for ensuring 
that the well is stabilized before conducting the test; the required 
duration of the test; the usage of correction factors and adjustments; 
and an option to use other procedures with approval from the Regional 
Supervisor. It also discusses conducting additional tests that the 
Regional Supervisor may require.
    Sec.  250.1153 When must I conduct a static bottomhole pressure 
survey? Static bottomhole pressure surveys are required on all new 
producing reservoirs, and annually on reservoirs with three or more 
producing completions. This proposed section addresses when operators 
must conduct static bottomhole pressure surveys and what information 
operators must submit to MMS. The proposed new provision would allow 
the operator to request a departure from this requirement from the 
Regional Supervisor, with appropriate justification.
Classifying Reservoirs
    Sec.  250.1154 How do I determine if my reservoir is sensitive? MMS 
requires that operators classify all reservoirs as either sensitive or 
non-sensitive. A sensitive reservoir is a reservoir in which high 
reservoir production rates would decrease ultimate recovery. This 
section would define the requirements for classifying reservoirs; when 
the Regional Supervisor may reclassify a reservoir; and when an 
operator may or must request reclassification of a reservoir. There are 
not substantive changes between the requirements of the current version 
of the rule and the proposed; this section would be reorganized and 
easier to read.
    Sec.  250.1155 What information must I submit for sensitive 
reservoirs? This proposed section defines what information MMS requires 
for sensitive reservoirs and when operators must submit that 
information. The only proposed change is that the Regional Supervisor 
may request that the operator submit Form MMS-127 (Sensitive Reservoir 
Information Report) and supporting information.
Approvals Prior to Production
    Sec.  250.1156 What steps must I take to receive approval to 
produce within 500 feet of a unit or lease line? In the current version 
of subpart K, a number of requirements, including approval for 
producing within 500 feet of a unit or lease line and basic 
classification requirements, are included in one section, 30 CFR 
250.1101. In the proposed rule, each of these issues is addressed in a 
separate section. Title 30 CFR 250.1156 would address only the approval 
and service fee for producing within 500 feet of a lease or unit line.
    The proposed approval requirements are clearer than in the current 
rule, and include issues addressed in NTL 97-16. In addition to 
receiving approval from the Regional Supervisor, operators must notify 
operators of adjacent leases. The requirement to notify adjacent 
operators would be clearer, and there is a list of information the 
notification would have to include.
    Sec.  250.1157 How do I receive approval to produce gas from an oil 
reservoir with an associated gas cap? This section would address how to 
receive approval to produce from an associated gas cap and its service 
fee. The required supporting information is listed in the table at 
proposed 30 CFR 250.1167 at the end of the rule.
    Sec.  250.1158 How do I receive approval to downhole commingle 
hydrocarbons? This section would address how to obtain MMS approval to

[[Page 9888]]

downhole commingle hydrocarbons and the service fee that must accompany 
your request. For downhole commingling in a competitive reservoir, the 
operator would be required to notify the operators of all leases that 
contain the reservoir. The request for approval must document this 
notification. Operators of the other leases would have 30 days after 
the notification to provide the Regional Supervisor with letters of 
acceptance or objection. If the notified operators do not respond 
within the specified period, the Regional Supervisor will assume the 
operators do not object. The Regional Supervisor will consider any 
objections, but may approve the commingling request to protect 
correlative rights. This section would also incorporate issues 
addressed in NTL's No. 99-G19 and 99-G20.
Production Rates
    Sec.  250.1159 May the Regional Supervisor limit my well or 
reservoir production rates? Generally, this proposed rule would 
eliminate MPR's and MER's. However, this section would retain the 
Regional Supervisor's authority to set an MPR for a producing well 
completion or an MER for a sensitive reservoir. If the Regional 
Supervisor sets an MPR or MER, it would be subject to the terms and 
conditions set by the Regional Supervisor. Those terms and conditions 
would include production restrictions that allow for normal variations 
and fluctuations in production rates.
Flaring, Venting, and Burning Hydrocarbons
    Sec.  250.1160 When may I flare or vent gas? The current regulation 
contains all of the flaring, venting, and burning regulations in one 
section. The proposed rule covers these in separate sections, so it is 
easier to find the requirements for a given situation. The new format 
also allows for the inclusion of more detail and clarification of 
flaring and venting situations that are not described in the current 
rule. Since there are many situations under which flaring and venting 
might occur, the table in this section reflects general categories that 
encompass the situations under which MMS would allow flaring or venting 
without approval from the Regional Supervisor. Under most 
circumstances, the proposed rule would allow operators to treat gas 
flashing from gas-well condensate similar to oil-well gas for flaring 
and venting approval purposes.
    The proposed rule would require operators to receive approval 
before flaring or venting gas in volumes higher than those specified in 
their previously-approved plans. This would enable MMS to ensure that 
flaring and venting activities are in compliance with environmental 
laws.
    The proposed rule would also allow the Regional Supervisor to 
specify flaring and venting volume limits (in addition to time limits) 
in order to prevent air quality degradation or the loss of reserves. 
This is sometimes necessary because offshore production facilities are 
now capable of flaring or venting extremely large volumes in a short 
amount of time.
    Sec.  250.1161 When may I flare or vent gas for extended periods of 
time? This section would define when operators must receive approval 
from the Regional Supervisor to flare or vent gas for an extended 
period of time. If there is a need to flare or vent a small amount of 
gas (less than 10 MCF per day) due to improperly working valves or pipe 
fittings and the Regional Supervisor determines that it is prudent to 
postpone the repair until a scheduled facility shutdown occurs, then 
the proposed rule would allow the Regional Supervisor to exempt the 
amount flared or vented from the time limits set in Sec.  250.1160.
    Sec.  250.1162 When may I burn produced liquid hydrocarbons? The 
regulations on burning produced liquid hydrocarbon would not change. 
Operators must receive approval from the Regional Supervisor in all 
cases before burning liquid hydrocarbons.
    Sec.  250.1163 How must I measure gas flaring or venting volumes, 
and liquid hydrocarbon burning volumes; and what records must I 
maintain? Requirements for measuring and keeping records on flaring, 
venting, and burning would change. The proposed rule would require 
vent/flare meters on all facilities that process more than 2,000 BOPD. 
Operators would be required to install these meters within 120 days 
after the final rule is published. This extended time frame is to 
accommodate operators that are required to install meters at multiple 
facilities. Facilities that do not process more than 2,000 BOPD when 
the final rule is published, but increase production above this level 
after the rule is published, would be required to install meters within 
90 days.
    Operators would be required to keep records on flaring, venting, 
and burning for 6 years to comply with 30 CFR Part 212--Records and 
Files Maintenance. The operators would be required to store these 
records on the facility for the first 2 years after the flaring, 
venting, or burning event. After that, the operator would be able to 
keep the records at a separate location, but they must be available for 
MMS review.
    The proposed rule would clarify reporting procedures and require 
operators to report flared and vented volumes separately. The 
previously discussed GAO report concluded that MMS should collect 
flared and vented volumes separately. MMS tentatively agrees with this 
conclusion, and does not believe it will pose a significant burden on 
operators because they already report the volumes of gas flared and 
vented to MMS on Form MMS-4054 (Oil and Gas Operations Report). 
Operators would only need to identify whether the gas volumes were 
flared or vented.
    The proposed rule would require operators to identify the 
facilities where the gas is flared or vented. This would enable MMS to 
directly compare volumes reported on Forms MMS-4054 with field records. 
This requirement would also reduce the burden on operators during 
royalty audits because operators would no longer have to reconstruct 
historical flare/vent allocations for MMS auditors.
    The proposed rule would require operators to retain meter 
recordings on facilities that require flare/vent meters. This would 
allow MMS to compare eyewitness observations with field records and 
ensure that flaring and venting incidents are properly recorded. MMS 
does not believe this would be a significant burden on those facilities 
with flare/vent meters because these meters typically record such 
events automatically and operators usually maintain these electronic 
records for their own purposes.
    In addition, the proposed rule would clarify when royalties are due 
on flared gas, vented gas, and burned liquid hydrocarbons under 30 CFR 
202.100 Royalty on Oil and 30 CFR 202.150 Royalty on Gas. As in the 
current rule, royalties would not be due if the hydrocarbons were 
unavoidably lost. In most cases, MMS will consider hydrocarbons that 
are flared, vented or burned with MMS approval as ``unavoidably lost'' 
and the operator would not be required to pay royalties. However, MMS 
would retain the authority to determine whether or not the loss was 
avoidable or due to negligence, even if approved by MMS. For example, 
if you received MMS approval to flare 100 MCF of gas per day, then 
actually flared 100,000 MCF of gas per day under conditions that would 
not have been approved, MMS might determine that the entire volume 
flared was ``avoidably lost'' and royalties would be due on the entire 
volume. MMS would also be able to

[[Page 9889]]

pursue civil penalties, under 30 CFR 250 subpart N--Outer Continental 
Shelf (OCS) Civil Penalties, if we determine that the loss was 
avoidable or due to negligence.
    Sec.  250.1164 What are the requirements for flaring or venting gas 
containing H<INF>2</INF>S? The proposed rule would require Regional 
Supervisor approval before emitting more than 15 lbs of SO<INF>2</INF> 
per hour per mile from shore. This would ensure that flaring activities 
are in compliance with environmental laws. MMS does not believe this 
would create an excessive burden on operators. The proposed regulations 
specify the records that the operator would have to keep. These records 
must be kept for 6 years, meeting the same requirements as in the 
previous section.
Enhanced Recovery
    Sec.  250.1165 What must I do for enhanced recovery operations? 
There are no significant proposed changes to the regulations regarding 
enhanced recovery operations. Operators would still be required to 
initiate enhanced recovery operations; receive Regional Supervisor 
approval for the plans; and submit reports on the substances injected, 
produced, or reproduced.
Special Alaska OCS Region Requirements
    Sec.  250.1166 What additional reporting is required for 
developments in the Alaska Region? This new section addresses special 
proposed reporting requirements for Alaska. This would require 
operators to submit an annual reservoir management report to the 
Regional Supervisor for any development in Alaska. If a development is 
regulated by both the MMS and the State of Alaska, the operator would 
be able to coordinate reporting requirements with MMS and the State of 
Alaska Oil and Gas Conservation Commission. This section would also 
require operators to request an MER for sensitive reservoirs in Alaska.
    This is necessary for the MMS Alaska Region to administer Section 7 
Agreements between the Secretary of the Interior and the Governor of 
the State of Alaska. Under existing Section 7 Agreements, oil and gas 
reserves underlying a common geologic structure must be unitized and 
the allocation of production between Federal and State leases for 
royalty payment must be based on recoverable oil and gas. Under 
agreement with the State, this determination will be based on reservoir 
performance following completion of the development drilling program 
and sustained production. Annual reservoir management plans enable the 
MMS to monitor recoverable oil and assure proper allocation of reserves 
for royalty payment and to be consistent with the State of Alaska 
requirements.
    This provision would also enable the MMS to manage its 
responsibility for conservation of resources on a real time basis. The 
number, type, spacing and sequencing of development wells (producers 
and injectors) will vary from the original approved development and 
production plan as more information on the reservoir is obtained. An 
annual reservoir management plan would enable the MMS to track 
development activities with the approved development and production 
plan and assure maximum recovery based on the most current knowledge of 
the reservoir.
Information Needed With Forms and for Approvals
    Sec.  250.1167 What information must I submit with forms and for 
approvals? This proposed table is designed to be an easy-to-use 
reference to determine the information and supporting documentation to 
submit to the Regional Supervisor and to remind lessees to pay the 
appropriate service fee. Forms MMS-126 (Well Potential Test Report) and 
MMS-127 (Sensitive Reservoir Information Report) would require 
supporting documents. Also, several operations covered under subpart K 
(gas cap production, downhole commingling, reservoir reclassification, 
and production within 500 feet of a unit or lease line), would require 
that the operator submit applications and supporting documents to the 
Regional Supervisor. All of these documents are covered in the table.

Questions

    In addition to comments on these proposed regulations, MMS is 
requesting comments on the following questions.
    1. Are these regulations well organized and easy to read?
    2. Is the submittal table useful?
    3. Is the 2,000 BOPD requirement for installing flare/vent meters 
reasonable? Are the cost estimates accurate?
    4. Would the requirement to install flare/vent meters pose a safety 
hazard by restricting flow during emergency facility blowdowns, or are 
accurate meters (such as ultrasonic meters) available that do not 
impede gas flow?
    5. Should MMS require operators to flare natural gas instead of 
venting it, under approved flaring and venting conditions? This 
question is based on a recommendation from the GAO report on flaring 
and venting natural gas, and reflects concerns about the amount of 
greenhouse gas that is released into the environment by venting. MMS is 
studying this recommendation before proposing any regulatory change. We 
would like comments on this issue, including comments related to 
additional costs, environmental impacts, and conditions or situations 
where flaring may not be advisable.

Procedural Matters

Public Availability of Comments

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

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

    This proposed rule is not a significant rule as determined by the 
Office of Management and Budget (OMB) and is not subject to review 
under E.O. 12866.
    (1) The proposed rule would not have an annual economic effect of 
$100 million or more on the economy. It would not adversely affect in a 
material way the economy, productivity, competition, jobs, the 
environment, public health or safety, or State, local, or tribal 
governments or communities. A cost-benefit and economic analysis is not 
required.
    This proposed rule revises the requirements for oil and gas 
production. The changes in the rule are not significant enough to have 
an impact on the economy or an economic sector, productivity, jobs, the 
environment, or other units of government. Some of the current 
requirements would be relaxed. For example, limits on production rates 
were eliminated in most cases. This would allow the operators to 
produce the oil and gas at the rates that they determine are best, and 
would not have a significant effect on any sector of the economy.
    (2) The proposed rule would not create a serious inconsistency or 
otherwise interfere with action taken or planned by another agency 
because MMS is the only Federal government agency directly involved in 
setting production requirements for the offshore oil and natural gas 
industry.
    (3) This proposed rule would not alter the budgetary effects of 
entitlements, grants, user fees or loan programs, or the rights and 
obligations of their recipients.

[[Page 9890]]

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

Regulatory Flexibility Act (RFA)

    The Department of the Interior certifies that this proposed rule 
would not have a significant economic effect on a substantial number of 
small entities as defined under the RFA (5 U.S.C. 601 et seq.). An 
initial Regulatory Flexibility Analysis is not required. Accordingly, a 
Small Entity Compliance Guide is not required.
    This rule applies to all lessees operating on the OCS. Lessees fall 
under the Small Business Administration's North American Industry 
Classification System (NAICS) code 211111, Crude Petroleum and Natural 
Gas Extraction. Under this NAICS code, companies with less than 500 
employees are considered small businesses. MMS estimates that 130 
lessees explore for and produce oil and gas on the OCS; approximately 
70 percent of them (91 companies) fall into the small business 
category. The proposed regulation would therefore affect a substantial 
number of small entities. However, we have determined that it would not 
have a significant economic effect on these small entities.
    One new requirement that would impose a cost to operators is a 
requirement to install flaring/venting meters on all facilities that 
process more than 2,000 BOPD. The GAO report on flaring and venting 
natural gas, released in July 2004, recommended that MMS require these 
meters to improve oversight. MMS agrees with this recommendation. MMS 
regulations allow flaring and venting in very limited circumstances. 
These meters would help MMS:
    <bullet> Verify the amounts of natural gas that operators flare or 
vent into the environment;
    <bullet> Prevent waste of resources;
    <bullet> Collect the proper royalties on avoidably flared or vented 
gas;
    <bullet> Determine if an operator is violating MMS regulations; and
    <bullet> Assess the impacts on the environment.
    In determining the criteria for which facilities must install the 
meters, MMS considered the cost of the meters and the amount of 
production needed to justify the cost. To ensure that the requirement 
to install flare/vent meters would not produce an undue burden on small 
companies, it was limited to those facilities that process more than an 
average of 2,000 BOPD.
    MMS estimates that 34 companies would have to install meters on 112 
facilities at an average cost of $77,000 per facility and a total cost 
to industry of $8,624,000 (112 x $77,000 = $8,624,000). Of those, nine 
companies are considered small businesses, based on the NAICS. These 
nine companies represent only 7 percent of the 130 operators on the 
OCS. We estimate that seven of these nine companies would need to 
install meters on one facility each; one company would need to install 
meters on two facilities; and one company would need to install meters 
on three facilities. This represents an average cost of $105,875 for 
each of the small companies (11 facilities x $77,000/9 companies). The 
average cost to non small companies would be $311,080 per company (101 
facilities x $77,000/25 companies). In addition, this does not 
represent an unfair burden to small companies because the cost of these 
meters is small in comparison to the revenues generated by the amount 
of oil processed by those facilities.
    Your comments are important. The Small Business and Agriculture 
Regulatory Enforcement Ombudsman and 10 Regional Fairness Boards were 
established to receive comments from small businesses about Federal 
agency enforcement actions. The Ombudsman will annually evaluate the 
enforcement activities and rate each agency's responsiveness to small 
business. If you wish to comment on the actions of MMS, call 1-888-734-
3247. You may comment to the Small Business Administration without fear 
of retaliation. Disciplinary action for retaliation by an MMS employee 
may include suspension or termination from employment with the DOI.

Small Business Regulatory Enforcement Fairness Act (SBREFA)

    The proposed rule is not a major rule under SBREFA (5 U.S.C. 
804(2)). This proposed rule:
    a. Would not have an annual effect on the economy of $100 million 
or more. This proposed rule revises the requirements for oil and gas 
production. The changes would not have an impact on the economy or an 
economic sector, productivity, jobs, the environment, or other units of 
government. Most of the new requirements are paperwork requirements, 
and would not add significant time to development and production 
processes. One new requirement would add new costs for some operators. 
Operators would be required to install flare/vent meters on any 
facility that processes more than an average of 2,000 BOPD. MMS 
estimates that 34 companies would have to install meters on 112 
facilities at an average cost of $77,000 per facility and a total cost 
to industry of $8,624,000 (112 x $77,000 = $8,624,000).
    b. Would not cause a major increase in costs or prices for 
consumers, individual industries, Federal, State, or local government 
agencies, or geographic regions.
    In most cases, this proposed rule would eliminate the requirement 
for operators to set limits on production rates, allowing the operators 
to determine the best rate to produce their reservoirs. The limits on 
burning, flaring, and venting are clearer. These limits would encourage 
conservation of our natural resources, without putting undue production 
restrictions on operators. There would be a new requirement to install 
meters on facilities that process more than an average of 2,000 BOPD. 
As discussed above, this requirement would not significantly increase 
the cost of doing business offshore.
    c. Would not have significant adverse effects on competition, 
employment, investment, productivity, innovation, or the ability of 
U.S.-based enterprises to compete with foreign-based enterprises. This 
proposed rule would eliminate the requirement for operators to set 
limits on production rates, allowing the operators to determine the 
best rate to produce their reservoirs. There are clearer limits on 
burning, flaring, and venting, which would encourage conservation of 
our natural resources.

Unfunded Mandates Reform Act (UMRA) of 1995

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

Takings Implication Assessment (Executive Order 12630)

    The proposed rule is not a governmental action capable of 
interference with constitutionally protected property rights. Thus, MMS 
did not need to prepare a Takings Implication Assessment according to

[[Page 9891]]

E.O. 12630, Governmental Actions and Interference with Constitutionally 
Protected Property Rights.

Federalism (Executive Order 13132)

    With respect to E.O. 13132, this proposed rule would not have 
federalism implications. This proposed rule would not substantially and 
directly affect the relationship between the Federal and State 
governments. To the extent that State and local governments have a role 
in OCS activities, this proposed rule would not affect that role.
    MMS has the authority to regulate offshore oil and gas production. 
State governments do not have authority over offshore production in 
Federal waters.

Civil Justice Reform (Executive Order 12988)

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

Paperwork Reduction Act (PRA)

    The proposed rule contains a collection of information that has 
been submitted to OMB for review and approval under Sec.  3507(d) of 
the PRA. As part of our continuing effort to reduce paperwork and 
respondent burdens, MMS invites the public and other Federal agencies 
to comment on any aspect of the reporting and recordkeeping burden. You 
may submit your comments on the information collection aspects of this 
proposed rule directly to the Office of Management and Budget (OMB), 
Office of Information and Regulatory Affairs, OMB Attention: Desk 
Officer for the Department of the Interior via OMB e-mail: (OIRA--
<a href="/cdn-cgi/l/email-protection" class="__cf_email__" data-cfemail="591d161a121c0d1936343b773c3629773e362f">[email protected]</a>); or by fax (202) 395-6566; identify with 1010-AD12. 
Send a copy of your comments to the Rules Processing Team (RPT), Attn: 
Rules Comments; 381 Elden Street, MS-4024; Herndon, Virginia 20170-
4817. Please reference ``Oil and Gas Production Requirements--AD12'' in 
your comments. You may obtain a copy of the supporting statement for 
the new collection of information by contacting the Bureau's 
Information Collection Clearance Officer at (202) 208-7744.
    The PRA provides that an agency may not conduct or sponsor, and a 
person is not required to respond to, a collection of information 
unless it displays a currently valid OMB control number. OMB is 
required to make a decision concerning the collection of information 
contained in these proposed regulations 30-60 days after publication of 
this document in the Federal Register. Therefore, a comment to OMB is 
best assured of having its full effect if OMB receives it by April 5, 
2007. This does not affect the deadline for the public to comment to 
MMS on the proposed regulations.
    The title of the collection of information for the rule is ``30 CFR 
250, Subpart K, Oil and Gas Production Requirements.'' The proposed 
regulations concern oil and gas production requirements, and the 
information is used in our efforts to conserve natural resources, 
prevent waste, and protect correlative rights, including the 
government's royalty interest.
    Respondents are the approximately 130 Federal oil and gas and 
sulphur lessees. Responses to this collection are mandatory. The 
frequency of response is on occasion, monthly, semi-annually, annually, 
and as a result of situations encountered depending upon the 
requirement. The information collection (IC) does not include questions 
of a sensitive nature. MMS will protect proprietary information 
according to the Freedom of Information Act (5 U.S.C. 552) and its 
implementing regulations (43 CFR part 2), and 30 CFR 250.196, ``Data 
and information to be made available to the public,'' and 30 CFR part 
252, ``OCS Oil and Gas Information Program.'' Proprietary information 
concerning geological and geophysical data will be protected according 
to 43 U.S.C. 1352.
    The collection of information required by the current subpart K 
regulations is approved under OMB Control Number 1010-0041. The 
proposed rule imposes minor changes to the information collection 
burden. The changes are:
    <bullet> Report to Minerals Revenue Management (MRM) measured gas 
flaring or venting and liquid hydrocarbon burning. Submit periodic 
reports of volumes of oil, gas, or other substances injected, produced, 
or produced for a second time. Both requirements and burdens are now 
reported to MRM and their respective burdens are covered under OMB 
Control Number 1010-0139 (-154 burden hours);
    <bullet> Request Regional Supervisor approval for emitting more 
than 15 lbs. of SO<INF>2</INF> (+10 burden hours);
    <bullet> Submit to Regional Supervisor air quality modeling 
analysis report. The proposed burden hours represent an adjustment to a 
current requirement for information that was not previously collected 
(+40 burden hours);
    <bullet> For Alaska Region Only: Submit to Regional Supervisor 
annual reservoir management report and supporting information. (At this 
time, the state requires the same information and MMS receives a copy). 
Alaska has started producing in state waters. If new development occurs 
in Federal waters, a minimal burden for submitting an annual reservoir 
management report, and burden hours for annual revisions are being 
added (+161 burden hours).
    <bullet> Maintain meter records for detailing gas flaring or 
venting, and liquid hydrocarbon burning for 6 years. These new burden 
requirements do not add additional burden hours.
    <bullet> General departure or alternative compliance requests (+5 
burden hours).
    The currently approved information collection for this subpart 
(1010-0041) will be superseded by this collection when final 
regulations take effect.
    Currently, regulations covered under OMB Control Number 1010-0041 
have 43,065 annual burden hours. MMS estimates the total annual 
reporting and recordkeeping ``hour'' burden for the proposed rule to be 
43,127 hours; this is an increase of 62 burden hours. With the 
exception of the recordkeeping requirement changes and the items 
identified as ``new'' in the following chart, the burden estimates 
shown are those that are estimated for the current subpart K 
regulations.

----------------------------------------------------------------------------------------------------------------
                                                                              Fee/non-hour cost
                                          Reporting &       ----------------------------------------------------
       30 CFR 250 Subpart K              recordkeeping                        Average number of    Annual burden
                                          requirement          Hour burden     annual responses        hours
----------------------------------------------------------------------------------------------------------------
1151(a), (c); 1155; 1165;          Submit form MMS-126 and                3  1,325 forms........           3,975
 1166(c); 1167.                     supporting information.
                                   Submit form MMS-127 and              2.2  2,189 forms........           4,816
                                    supporting information.

[[Page 9892]]

 
                                   Submit form MMS-128 and           0.1--3  13,000 GOM forms...          1,336*
                                    supporting information.                  600 POCS forms.....
1151(b)..........................  Request extension of                 0.5  37 requests........              19
                                    time to submit results
                                    of semiannual well test.
1152(b), (c).....................  Obtain Regional                      0.5  37 requests........              19
                                    Supervisor approval to
                                    conduct well testing
                                    using alternative
                                    procedures; conduct
                                    tests/retests to
                                    establish proper MPR or
                                    MER; conduct multipoint
                                    backpressure test for
                                    open flow potential.
1152(d)..........................  Provide advance notice               0.5  10 notices.........               5
                                    of time and date of
                                    well tests.
1153.............................  Submit results of all                 14  1,270 surveys......          17,780
                                    static bottomhole                     1  120 survey waivers.             120
                                    pressure surveys
                                    obtained by lessee
                                    using form MMS-140.
                                    Request departure
                                    requirement w/
                                    justification to
                                    Regional Supervisor;
                                    submit with Form MMS-
                                    140 and supporting
                                    information.
1154; 1167.......................  Request reclassification               6  20 requests........             120
                                    of reservoir for
                                    Regional Supervisor
                                    approval and submit
                                    supporting information.
1156; 1167.......................  Request approval to                    5  50 requests........             250
                                    produce within 500 feet
                                    of a unit or lease line
                                    and submit supporting
                                    information; notify
                                    operators; provide
                                    proof of date to
                                    Regional Supervisor.
                                                            ----------------------------------------------------
                                                                        3,300 x 50 requests = $165,000
                                                            ----------------------------------------------------
1157; 1167.......................  Request approval to                   12  125 requests.......           1,500
                                    produce gas cap of a
                                    sensitive reservoir and
                                    submit supporting
                                    information; obtain
                                    approval to produce gas
                                    from an oil reservoir
                                    with an associated gas
                                    cap.
                                                            ----------------------------------------------------
                                                                       $4,200 x 125 requests = $525,000
                                                            ----------------------------------------------------
1158; 1167.......................  Submit request to                      6  119 applications...             714
                                    downhole commingle
                                    hydrocarbons and
                                    supporting information;
                                    notify operators;
                                    provide proof of date
                                    to Regional Supervisor.
                                                            ----------------------------------------------------
                                                                     $4,900 x 119 applications = $583,100
                                                            ----------------------------------------------------
1160; 1161.......................  Request Regional                     0.5  1,007 requests.....             504
                                    Supervisor approval/
                                    inform to flare or vent
                                    oil-well gas or gas-
                                    well gas/exceed volume;
                                    submit documentation.
                                                            ----------------------------------------------------
1162; 1163(e)....................  Request approval to burn             0.5  60 requests........              30
                                    produced liquid
                                    hydrocarbons; submit
                                    documentation.
NEW 1163.........................  Initial purchase and                   0  112................               0
                                    install gas meters to
                                    measure the amount of
                                    gas flared or vented.
                                    This is a non-hour cost
                                    burden.
                                                            ----------------------------------------------------
                                                                     112 meters @ $77,000 ea = $8,624,000
                                  ------------------------------------------------------------------------------
NEW 1163(b); 1165(c).............  Report to MRM measured gas flaring or venting and liquid                    0
                                    hydrocarbon burning--burden covered under 1010-0139
                                  ------------------------------------------------------------------------------
NEW 1164(b)(1)...................  Request Regional                     0.5  20 requests........              10
                                    Supervisor approval for
                                    emitting more than 15
                                    lbs. of SO2.
                                  ------------------------------------------------------------------------------
1164(b)(2).......................  H2S Contingency, Exploration, or Development and Production                 0
                                    Plans--burden covered under 1010-0141 and 1010-0151
                                  ------------------------------------------------------------------------------
NEW 1164(b)(3)...................  Submit to Regional                    40  1 modeling analysis              40
                                    Supervisor air quality
                                    modeling analysis.
1164(c)..........................  Submit monthly reports                 2  3 operators x 12                 72
                                    of flared or vented gas                   mos. = 36.
                                    containing H2S.
1165.............................  Submit proposed plan for              12  27 plans...........             324
                                    enhanced recovery
                                    operations.
                                  ------------------------------------------------------------------------------
1165(c)..........................  Submit periodic reports of volumes of oil, gas, or other                    0
                                    substances injected, produced, or produced for a second
                                    time--burden covered under OMB approval 1010-0139

[[Page 9893]]

 
NEW 1166.........................  Alaska Region only:                    1  1 (required by                    1
                                    submit to Regional       ..............   State, MMS gets     ..............
                                    Supervisor annual        ..............   copy).              ..............
                                    reservoir management                100  1 new develop not               100
                                    report and supporting                     State lands.
                                    information.
                                  ---------------------------------------------------------------
                                                                         20  3 annual revisions.              60
NEW 1150-1167....................  General departure or                   1  5..................               5
                                    alternative compliance
                                    requests not
                                    specifically covered
                                    elsewhere in subpart K.
----------------------------------------------------------------------------------------------------------------
                             Reporting Subtotal                              20,175.............          31,800
----------------------------------------------------------------------------------------------------------------
1163(c), (d).....................  Maintain records for 6                13  869 platforms......          11,297
                                    years detailing gas
                                    flaring or venting;
                                    maintain meter records
                                    and provide copies if
                                    requested.
1163(c)..........................  Maintain records for 6               0.5  60 occurrences.....              30
                                    years detailing liquid
                                    hydrocarbon burning;
                                    maintain meter records
                                    and provide copies if
                                    requested.
----------------------------------------------------------------------------------------------------------------
                           Recordkeeping Subtotal                            929................          11,327
----------------------------------------------------------------------------------------------------------------
                                Total Burden                                 21,104.............          43,127
----------------------------------------------------------------------------------------------------------------
                                                                                                      $9,897,100
----------------------------------------------------------------------------------------------------------------
* Reporting burden for this form is estimated to average 0.1 to 3 hours per form depending on the number of well
  tests reported, including the time for reviewing instructions, gathering and maintaining data, and completing
  and reviewing the form. See breakdown for form MMS-128 above.

    (a) MMS specifically solicits comments on the following questions:
    (1) Is the proposed collection of information necessary for MMS to 
properly perform its functions, and will it be useful?
    (2) Are the estimates of the burden hours of the proposed 
collection reasonable?
    (3) Do you have any suggestions that would enhance the quality, 
clarity, or usefulness of the information to be collected?
    (4) Is there a way to minimize the information collection burden on 
those who are to respond, including the use of appropriate automated 
electronic, mechanical, or other forms of information technology?
    (b) In addition, the PRA requires agencies to estimate the total 
annual reporting and recordkeeping ``non-hour cost'' burden resulting 
from the collection of information. Other than the cost recovery fees 
listed in the burden table, and the fee for installing flaring/venting 
meters (Sec.  250.1163), we have not identified any other costs, and we 
solicit your comments on this item. For reporting and recordkeeping 
only, your response should split the cost estimate into two components: 
(1) Total capital and startup cost component and (2) annual operation, 
maintenance, and purchase of services components. Your estimates should 
consider the costs to generate, maintain, disclose or provide the 
information. You should describe the methods you use to estimate major 
cost factors, including system and technology acquisition, expected 
useful life of capital equipment, discount rate(s), and the period over 
which you incur costs. Capital and start-up costs include, among other 
items, computers and software you purchase to prepare for collecting 
information; monitoring, sampling, drilling, and testing equipment; and 
record storage facilities. Generally, our estimates should not include 
equipment or services purchased: before October 1, 1995; to comply with 
requirements not associated with the information collection; for 
reasons other than to provide information or keep records for the 
Government; or as part of customary and usual business or private 
practices.

National Environmental Policy Act (NEPA) of 1969

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

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

    Executive Order 13211 requires the agency to prepare a Statement of 
Energy Effects when it takes a regulatory action that is identified as 
a significant energy action. This proposed rule is not a significant 
energy action, and therefore would not require a Statement of Energy 
Effects because it:
    a. Is not a significant regulatory action under E.O. 12866,
    b. Is not likely to have a significant adverse effect on the 
supply, distribution, or use of energy, and
    c. Has not been designated by the Administrator of the Office of 
Information and Regulatory Affairs, OMB, as a significant energy 
action.

Consultation With Indian Tribes (Executive Order 13175)

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

Clarity of This Regulation (Executive Order 12866)

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

[[Page 9894]]

    (1) Are the requirements in the proposed rule clearly stated?
    (2) Does the proposed rule contain technical language or jargon 
that interferes with its clarity?
    (3) Does the format of the proposed rule (grouping and order of 
sections, use of headings, paragraphs, etc.) aid or reduce its clarity?
    (4) Is the description of the proposed rule in the ``Supplementary 
Information'' section of this preamble helpful in understanding the 
rule?
    Send a copy of any comments that concern how we could make this 
proposed rule easier to understand to: Office of Regulatory Affairs; 
Department of the Interior, Room 7229; 1849 C Street, NW., Washington, 
DC 20240. You may also e-mail the comments to this address: 
<a href="/cdn-cgi/l/email-protection#99dce1eafcfad9f0f6eab7fdf6f0b7fef6ef"><span class="__cf_email__" data-cfemail="387d404b5d5b7851574b165c5751165f574e">[email protected]</span></a>.

List of Subjects in 30 CFR Part 250

    Continental shelf, Environmental impact statements, Environmental 
protection, Government contracts, Investigations, Oil and gas 
exploration, Penalties, Pipelines, Public lands--mineral resources, 
Public lands--rights-of-way, Reporting and recordkeeping requirements, 
Sulphur.

    Dated: January 31, 2007.
C. Stephen Allred,
Assistant Secretary--Land and Minerals Management.
    For the reasons stated in the preamble, Minerals Management Service 
(MMS) proposes to revise 30 CFR part 250 as follows:

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

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


Sec.  250.105  Definitions.

* * * * *
    Flaring means the burning of gas in the field as it is released 
into the atmosphere.
* * * * *
    Sensitive reservoir means a reservoir in which high reservoir 
production rates will decrease ultimate recovery.
* * * * *
    Venting means the release of gas into the atmosphere without 
igniting it. This includes gas that is released underwater and bubbles 
to the atmosphere.
* * * * *
    3. In Sec.  250.125, revise the table in paragraph (a) to read as 
follows:


Sec.  250.125  Service fees.

    (a) * * *

                            Service Fee Table
------------------------------------------------------------------------
 Service--processing of the
         following:                Fee amount          30 CFR citation
------------------------------------------------------------------------
Change in Designation of      $150................  Sec.   250.143.
 Operator.
Suspension of Operations/     $1,800..............   Sec.   250.171.
 Suspension of Production
 (SOO/SOP) Request.
Exploration Plan (EP).......  $3,250 for each        Sec.   250.211.
                               surface location,
                               no fee for
                               revisions.
Development and Production    $3,750 for each well   Sec.   250.241(e).
 Plan (DPP) or Development     proposed, no fee
 Operations Coordination       for revisions.
 Document (DOCD).
Deepwater Operations Plan...  $3,150..............   Sec.   250.292(p).
Conservation Information      $24,200.............   Sec.   250.296(a).
 Document.
Application for Permit to     $1,850..............
 Drill (APD; Form MMS-123).
                              Initial applications  Sec.   250.410(d);
                               only, no fee for      Sec.   250.411;
                               revisions             Sec.   250.460;
                                                     Sec.   250.513(b);
                                                     Sec.   250.515;
                                                     Sec.   250.1605;
                                                     Sec.   250.1617(a);
                                                     Sec.   250.1622.
Application for Permit to     $110................  Sec.   250.460; Sec.
 Modify (APM; Form MMS-124).                           250.465(b); Sec.
                                                      250.513(b); Sec.
                                                     250.515; Sec.
                                                     250.613(b); Sec.
                                                     250.615; Sec.
                                                     250.1618(a); Sec.
                                                     250.1622; Sec.
                                                     250.1704(g).
New Facility Production       $4,750..............
 Safety System Application
 for facility with more than
 125 components.
                              A component is a       Sec.   250.802(e).
                               piece of equipment
                               or ancillary system
                               that is protected
                               by one or more of
                               the safety devices
                               required by API RP
                               14C (incorporated
                               by reference as
                               specified in Sec.
                               250.198)
                              (Additional fee of
                               $12,500 will be
                               charged if MMS
                               deems it necessary
                               to visit a facility
                               offshore; and
                               $6,500 to visit a
                               facility in a
                               shipyard)
New Facility Production       $1,150..............   Sec.   250.802(e).
 Safety System Application    (Additional fee of
 for facility with 25-125      $7,850 will be
 components.                   charged if MMS
                               deems it necessary
                               to visit a facility
                               offshore; and
                               $4,500 to visit a
                               facility in a
                               shipyard).
New Facility Production       $570................   Sec.   250.802(e).
 Safety System Application
 for facility with fewer
 than 25 components.
Production Safety System      $530................   Sec.   250.802(e).
 Application--Modification
 with more than 125
 components reviewed.
Production Safety System      $190................   Sec.   250.802(e).
 Application--Modification
 with 25-125 components
 reviewed.

[[Page 9895]]

 
Production Safety System      $80.................   Sec.   250.802(e).
 Application--Modification
 with fewer than 25
 components reviewed.
Platform Application--        $19,900.............   Sec.   250.905(k).
 Installation--under the
 Platform Verification
 Program.
Platform Application--        $2,850..............   Sec.   250.905(k).
 Installation--Fixed
 Structure Under the
 Platform Approval Program.
Platform Application--        $1,450..............   Sec.   250.905(k).
 Installation--Caisson/Well
 Protector.
Platform Application--        $3,400..............   Sec.   250.905(k).
 Modification/Repair.
New Pipeline Application      $3,100..............   Sec.   250.1000(b).
 (Lease Term).
Pipeline Application--        $1,800..............   Sec.   250.1000(b).
 Modification (Lease Term).
Pipeline Application--        $3,650..............   Sec.   250.1000(b).
 Modification (ROW).
Pipeline Repair Notification  $340................   Sec.   250.1008(e).
Pipeline Right-of-Way (ROW)   $2,350..............   Sec.   250.1015.
 Grant Application.
Pipeline Conversion of Lease  $200................   Sec.   250.1015.
 Term to ROW.
Pipeline ROW Assignment.....  $170................   Sec.   250.1018.
500 Feet From Lease/Unit      $3,300..............   Sec.   250.1156.
 Line Production Request.
Gas Cap Production Request..  $4,200..............   Sec.   250.1157.
Downhole Commingling Request  $4,900..............   Sec.   250.1158.
Complex Surface Commingling   $3,550..............  Sec.   250.1202(a);
 and Measurement Application.                        Sec.   250.1203(b);
                                                     Sec.   250.1204(a).
Simple Surface Commingling    $1,200..............  Sec.   250.1202(a);
 and Measurement Application.                        Sec.   250.1203(b);
                                                     Sec.   250.1204(a).
Voluntary Unitization         $10,700.............   Sec.   250.1303.
 Proposal or Unit Expansion.
Unitization Revision........  $760................   Sec.   250.1303.
Application to Remove a       $4,100..............   Sec.   250.1727.
 Platform or Other Facility.
Application to Decommission   $1,000..............   Sec.   250.1751(a)
 a Pipeline (Lease Term).                            or Sec.
                                                     250.1752(a).
Application to Decommission   $1,900..............   Sec.   250.1751(a)
 a Pipeline (ROW).                                   or Sec.
                                                     250.1752(a).
------------------------------------------------------------------------

* * * * *
    4. Revise subpart K to read as follows:
Subpart K--Oil and Gas Production Requirements

General

Sec.
250.1150 What are the general reservoir production requirements?

Well Tests and Surveys

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?

Classifying Reservoirs

250.1154 How do I determine if my reservoir is sensitive?
250.1155 What information must I submit for sensitive reservoirs?

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?
250.1157 How do I receive approval to produce gas from an oil 
reservoir with an associated gas cap?
250.1158 How do I receive approval to downhole commingle 
hydrocarbons?

Production Rates

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

Flaring, Venting, and Burning 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?
250.1164 What are the requirements for flaring or venting gas 
containing H<INF>2</INF>S?

Enhanced Recovery

250.1165 What must I do for enhanced recovery operations?

Special Alaska OCS Region Requirements

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

Information Needed with Forms and for Approvals

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

Subpart K--Oil and Gas Production Requirements

General


Sec.  250.1150  What are the general reservoir production requirements?

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

Well Tests and Surveys


Sec.  250.1151  How often must I conduct well production tests?

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

------------------------------------------------------------------------
                                            And you must submit to the
           You must conduct:                   Regional Supervisor:
------------------------------------------------------------------------
(1) A well-flow potential test on all    Form MMS-126, Well Potential
 new, recompleted, or reworked well       Test Report, along with the
 completions within 30 days of the date   supporting data as listed in
 of first continuous production.          the table in Sec.   250.1167,
                                          within 15 days after the end
                                          of the test period.

[[Page 9896]]

 
(2) At least one well test during a      Results on Form MMS-128,
 calendar half-year for each producing    Semiannual Well Test Report,
 completion.                              of the most recent well test
                                          obtained. This must be
                                          submitted within 45 days after
                                          the end of the calendar half-
                                          year
------------------------------------------------------------------------

    (b) You may request an extension from the Regional Supervisor if 
you cannot submit the results of a semiannual well test within the 
specified time.
    (c) You must submit an original and one copy of the form required 
by paragraph (a) of this section, as listed in the table in Sec.  
250.1167. You must include one public information copy with each 
submittal in accordance with Sec. Sec.  250.190 and 250.196, and mark 
that copy ``Public Information.''


Sec.  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[deg]F for all tests; and
    (5) Use measured specific gravity values to calculate gas volumes.
    (b) You may request approval from the Regional Supervisor to 
conduct a well test using alternative procedures if you can demonstrate 
test reliability under those procedures.
    (c) The Regional Supervisor may also require you to conduct the 
following tests and complete them within the specified time period:
    (1) A retest or a prolonged test of a well completion if it is 
determined to be necessary for the proper establishment of a Maximum 
Production Rate (MPR) or a Maximum Efficient Rate (MER); and
    (2) A multipoint back-pressure test to determine the theoretical 
open-flow potential of a gas well.
    (d) An MMS representative may witness any well test. Upon request, 
you must provide advance notice to the Regional Supervisor of the times 
and dates of well tests.


Sec.  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       Annual static bottomhole
 producing completions.                   pressure surveys in a
                                          sufficient number of key wells
                                          to establish an average
                                          reservoir pressure. The
                                          Regional Supervisor may
                                          require that bottomhole
                                          pressure surveys be performed
                                          on specific wells.
------------------------------------------------------------------------

    (b) Your bottomhole pressure survey must meet the following 
requirements:
    (1) You must shut-in the well for a minimum period of 4 hours to 
ensure stabilized conditions; and
    (2) The bottomhole pressure survey must consist of a pressure 
measurement at mid-perforation, and pressure measurements and gradient 
information for at least four gradient stops coming out of the hole.
    (c) You must submit to the Regional Supervisor the results of all 
static bottomhole pressure surveys on Form MMS-140, Bottomhole Pressure 
Survey Report, within 60 days after the date of the survey.
    (d) The Regional Supervisor may grant a departure from the 
requirement to run a static bottomhole pressure survey. You must 
request a departure by letter, along with Form MMS-140, Bottomhole 
Pressure Survey Report. You must include sufficient justification to 
support the departure request.

Classifying Reservoirs


Sec.  250.1154  How do I determine if my reservoir is sensitive?

    (a) You must determine whether each reservoir is sensitive. You 
must classify the reservoir as sensitive if:
    (1) Under initial conditions it is an oil reservoir with an 
associated gas cap;
    (2) At any time there are near-critical fluids; or
    (3) The reservoir is undergoing secondary or tertiary recovery.
    (b) For the purposes of this subpart, near-critical fluids are 
those fluids that occur in high temperature, high-pressure reservoirs 
where it is not possible to define the liquid-gas contact or fluids in 
reservoirs that are near bubble point or dew point conditions.
    (c) The Regional Supervisor may reclassify a reservoir when 
available information warrants reclassification.
    (d) If available information indicates that a reservoir previously 
classified as non-sensitive is now sensitive, you must submit a request 
to the Regional Supervisor to reclassify the reservoir. You must 
include supporting information, as listed in the table in Sec.  
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 Sec.  250.1167, with 
your request.


Sec.  250.1155  What information must I submit for sensitive 
reservoirs?

    You must submit an original and three copies of Form MMS-127 and 
supporting information, as listed in the table in Sec.  250.1167 to the 
Regional Supervisor. You must include one public information copy with 
each submittal in accordance with Sec. Sec.  250.190 and 250.196, and 
mark that copy ``Public Information.'' You must submit this 
information:
    (a) Within 45 days after beginning production from the reservoir or 
discovering that it is sensitive;
    (b) At least once during the calendar year;
    (c) Within 45 days after you revise reservoir parameters; and

[[Page 9897]]

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

Approvals Prior to Production


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

    (a) You must obtain approval from the Regional Supervisor before 
you start producing from a well that has any portion of the completed 
interval less than 500 feet from a unit or lease line. Submit to MMS 
the service fee listed in Sec.  250.125 and the Regional Supervisor 
will determine whether approval of your request will maximize ultimate 
recovery, avoids the waste of natural resources or whether it is 
necessary to protect correlative rights. You do not need to obtain 
approval if the adjacent leases or units have the same unit, lease, and 
royalty interests as the lease or unit you plan to produce. You do not 
need to obtain approval if the adjacent block is unleased.
    (b) You must notify the operator(s) of adjacent property(ies) that 
are within 500 feet of the completion, if the adjacent acreage is a 
leased block in the Federal OCS. You must provide the Regional 
Supervisor proof of the date of the notification. The operators of the 
adjacent properties have 30 days after receiving the notification to 
provide the Regional Supervisor letters of acceptance or objection. If 
an adjacent operator does not respond within 30 days, the Regional 
Supervisor will presume there are no objections and proceed with a 
decision. The notification must include:
    (1) The well name;
    (2) The rectangular coordinates (x, y) of the location of the top 
and bottom of the completion or target completion reference to the 
North American Datum 1983, and the subsea depths of the top and bottom 
of the completion or target completion;
    (3) The distance from the completion or target completion to the 
unit or lease line at its nearest point; and
    (4) A statement indicating whether or not it will be a high-
capacity completion having a perforated or open hole interval greater 
than 150 feet measured depth.


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

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


Sec.  250.1158  How do I receive approval to downhole commingle 
hydrocarbons?

    (a) Before you perforate a well, you must request and receive 
approval from the Regional Supervisor to commingle hydrocarbons 
produced from multiple reservoirs within a common wellbore. The 
Regional Supervisor will determine whether your request maximizes 
ultimate recovery and avoids the waste of natural resources. You must 
include the service fee listed in Sec.  250.125 and the supporting 
information, as listed in the table in Sec.  250.1167, with your 
request.
    (b) If one or more of the commingled reservoirs is a competitive 
reservoir, you must notify the operators of all leases that contain the 
reservoir that you intend to downhole commingle the reservoirs. Your 
request for approval of downhole commingling must include proof of the 
date of this notification. The notified operators have 30 days after 
notification to provide the Regional Supervisor with letters of 
acceptance or objection. If the notified operators do not respond 
within the specified period, the Regional Supervisor will assume the 
operators do not object and proceed with a decision.

Production Rates


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

    (a) The Regional Supervisor may set a Maximum Production Rate (MPR) 
for a producing well completion, or set a Maximum Efficient Rate (MER) 
for a reservoir, or both, if the Regional Supervisor determines that an 
excessive production rate could harm ultimate recovery. An MPR or MER 
will be based on well tests and any limitations imposed by well and 
surface equipment, sand production, reservoir sensitivity, gas-oil and 
water-oil ratios, location of perforated intervals, and prudent 
operating practices.
    (b) If the Regional Supervisor sets an MPR for a producing well 
completion, or an MER for a reservoir, you may not exceed those rates 
except due to normal variations and fluctuations in production rates, 
as set by the Regional Supervisor.

Flaring, Venting, and Burning Hydrocarbons


Sec.  250.1160  When may I flare or vent gas?

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

------------------------------------------------------------------------
               Condition                     Additional requirements
------------------------------------------------------------------------
(1) When the gas is lease use gas        The volume of gas flared or
 (produced natural gas which is used on   vented may not exceed the
 or for the benefit of lease operations   amount necessary for its
 such as gas used to operate production   intended purpose. Burning
 facilities) or is used as an additive    waste products may require
 necessary to burn waste products, such   approval under other
 as H2S.                                  regulations.
(2) During the restart of a facility     Flaring or venting may not
 that was shut in because of weather      exceed 48 cumulative hours
 conditions, such as a hurricane.         without Regional Supervisor
                                          approval.
(3) During the blow down of              (i) You must report the
 transportation pipelines downstream of   location, time, flare/vent
 the royalty meter.                       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  You may not exceed 48
 a well, drill-stem testing, production   cumulative hours of flaring or
 testing, other well-evaluation           venting per testing operation
 testing, or the necessary blow down to   on a single completion without
 perform these procedures.                Regional Supervisor approval.
(5) When properly working equipment      You may not flare or vent more
 yields flash gas (natural gas released   than an average 50 MCF per day
 from liquid hydrocarbons as a result     during any calendar month
 of a decrease in pressure, an increase   without Regional Supervisor
 in temperature, or both) from storage    approval.
 vessels or other low-pressure
 production vessels, and you cannot
 economically recover this flash gas.

[[Page 9898]]

 
(6) When the equipment works properly    (i) For oil-well gas and gas-
 but there is a temporary upset           well flash gas (natural gas
 condition, such as a hydrate or          released from condensate as a
 paraffin plug.                           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         (i) For oil-well gas and gas-
 properly, including equipment            well flash gas, you may not
 maintenance and repair, or when you      exceed 48 continuous hours of
 must relieve system pressures.           flaring or venting without
                                          Regional Supervisor approval.
                                         (ii) For primary gas-well gas,
                                          you may not exceed 2
                                          continuous hours of flaring or
                                          venting without Regional
                                          Supervisor approval.
                                         (iii) You may not exceed 144
                                          cumulative hours of flaring or
                                          venting during a calendar
                                          month without Regional
                                          Supervisor approval.
                                         (iv) The continuous and
                                          cumulative hours allowed under
                                          this paragraph may be counted
                                          separately from the hours
                                          under paragraph (a)(6) of this
                                          section.
------------------------------------------------------------------------

    (b) You must inform the Regional Supervisor and receive approval to 
flare or vent gas before you exceed the volume specified in your 
Development and Production Plan submitted under subpart B of this part, 
even if the flaring or venting does not require approval under 
paragraph (a) of this section. The Regional Supervisor will determine 
whether your proposed flaring or venting complies with air emission 
thresholds under subpart C of this part.
    (c) The Regional Supervisor may establish alternative approval 
procedures to cover situations where you cannot contact the MMS office, 
such as during non-office hours.
    (d) The Regional Supervisor may specify a volume limit, or a 
shorter time limit than specified elsewhere in this part, in order to 
prevent air quality degradation or loss of reserves.
    (e) The Regional Supervisor will evaluate your request for gas 
flaring or venting and determine if the loss of hydrocarbons is due to 
negligence, or could be avoided.
    (f) If you flare or vent gas without the required approval, or if 
the Regional Supervisor determines that you were negligent or could 
have avoided flaring or venting the gas, the hydrocarbons will be 
considered avoidably lost or wasted. You must pay royalties on the loss 
or waste, according to part 202 of this title. You must value any gas 
or liquid hydrocarbons avoidably lost or wasted under the provisions of 
part 206 of this title.


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

    You may flare or vent oil-well gas and gas-well flash gas for a 
period that the Regional Supervisor will specify, and which will not 
exceed 1 year, if the Regional Supervisor approves your request for one 
of the following reasons:
    (a) You initiate an action which, when completed, will eliminate 
flaring and venting;
    (b) You submit to the Regional Supervisor an evaluation supported 
by engineering, geologic, and economic data indicating that the oil and 
gas produced from the well(s) will not economically support the 
facilities necessary to sell the gas; or to use the gas on or for the 
benefit of, the lease; or
    (c) The Regional Supervisor determines that an improperly working 
valve, pipe fitting, or similar component results in flaring or venting 
of less than 10 MCF per day, and that it is prudent to repair the leak 
at a later date. The Regional Supervisor may exempt this flaring or 
venting from the time limits set in Sec.  250.1160.


Sec.  250.1162  When may I burn produced liquid hydrocarbons?

    (a) You must request and receive approval from the Regional 
Supervisor to burn any produced liquid hydrocarbons. The Regional 
Supervisor may allow you to burn condensate if you demonstrate that 
transporting it to market or re-injecting it is not feasible or poses a 
significant risk of harm to offshore personnel or the environment. In 
most cases, the Regional Supervisor will not allow you to burn more 
than 300 barrels of condensate in total during unloading or cleaning of 
a well, drill-stem testing, production testing, or other well-
evaluation testing.
    (b) The Regional Supervisor will evaluate your request for liquid 
hydrocarbon burning, and determine if the loss of hydrocarbons is due 
to negligence or could be avoided.
    (c) If you burn liquid hydrocarbons without the required approval, 
or if the Regional Supervisor determines that you were negligent or 
could have avoided burning liquid hydrocarbons, the hydrocarbons will 
be considered avoidably lost or wasted. You must pay royalties on the 
loss or waste, according to part 202 of this title. You must value any 
liquid hydrocarbons avoidably lost or wasted under the provisions of 
part 206 of this title.


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

    (a) If your facility processes more than an average of 2,000 BOPD 
during [MONTH AND YEAR IN WHICH FINAL RULE IS PUBLISHED], you must 
install flare/vent meters within 120 days after [THE MONTH AND YEAR IN 
WHICH THE FINAL RULE IS PUBLISHED]. If your facility processes more 
than an average of 2,000 BOPD during a calendar month after [MONTH AND 
YEAR IN WHICH FINAL RULE IS PUBLISHED], you must install flare/vent 
meters within 90 days after the end of the month in which the average 
amount of oil processed exceeds 2,000 BOPD.
    (1) The flare/vent meters must measure all flared and vented gas 
within 2 percent accuracy.
    (2) You must calibrate the meters regularly, in accordance with the 
manufacturer's recommendation, or at least once every 6 months, 
whichever is shorter.
    (b) You must report all hydrocarbons produced from a well 
completion, including all gas flared, gas vented, and liquid 
hydrocarbons burned, to Minerals Revenue Management on Form MMS-4054 
(Oil and Gas Operations Report), in accordance with Sec.  216.53 of 
this title.

[[Page 9899]]

    (1) You must report the amount of gas flared and the amount of gas 
vented separately.
    (2) You may classify and report gas used to operate equipment on 
the facility (such as gas used to power engines, gas used as pilot 
lights, instrument gas, purge gas used to prevent oxygen from entering 
the flare or vent stack, sparge gas used to regenerate glycol, and 
blanket gas used to maintain pressure in low pressure vessels) as lease 
use gas.
    (3) You must report the amount of gas flared and vented at each 
facility on a lease or unit basis. Gas flared and vented from multiple 
facilities on a single lease or unit must be reported separately.
    (c) You must prepare and maintain records detailing gas flaring, 
gas venting, and liquid hydrocarbon burning for each facility. You must 
maintain these records for the period specified in part 212 of this 
title. You must keep these records on the facility for 2 years and have 
them available for inspection by MMS representatives. After 2 years, 
you must maintain the records, allow MMS representatives to inspect the 
records upon request, and provide copies to the Regional Supervisor 
upon request, but you are not required to keep them on the facility. 
The records must include, at a minimum:
    (1) Daily volumes of gas flared, gas vented, and liquid 
hydrocarbons burned;
    (2) Number of hours of gas flaring, gas venting, and liquid 
hydrocarbon burning, on a daily basis;
    (3) A list of the wells contributing to gas flaring, gas venting, 
and liquid hydrocarbon burning, along with gas-oil ratio data;
    (4) Reasons for gas flaring, gas venting, and liquid hydrocarbon 
burning; and
    (5) Documentation of all required approvals.
    (d) If your facility is required to have flare/vent meters, you 
must maintain the meter recordings for the period specified in 
Sec. Sec.  212.50 and 212.51 of this title. You must keep these 
recordings on the facility for 2 years and have them available for 
inspection by MMS representatives. After 2 years, you must maintain the 
recordings, allow MMS representatives to inspect the recordings upon 
request, and provide copies to the Regional Supervisor upon request, 
but are not required to keep them on the facility. These recordings 
must include the begin times, end times, and volumes for all flaring 
and venting incidents.
    (e) If your flaring or venting of gas, or burning of liquid 
hydrocarbons, required written or oral approval, you must submit 
documentation to the Regional Supervisor summarizing the location, 
dates, number of hours, and volumes of gas flared, gas vented, and 
liquid hydrocarbons burned under the approval, as required under Sec.  
250.140.


Sec.  250.1164  What are the requirements for flaring or venting gas 
containing H<INF>2</INF>S?

    (a) You may not vent gas containing H<INF>2</INF>S, except for 
minor releases during maintenance and repair activities that do not 
result in a 15-minute time-weighted average atmosphere concentration of 
H<INF>2</INF>S of 20 ppm or higher anywhere on the platform.
    (b) You may flare gas containing H<INF>2</INF>S only if you meet 
the requirements of Sec. Sec.  250.1160, 250.1161, 250.1163, and the 
following additional requirements:
    (1) You may not emit more than 15 lbs of SO<INF>2</INF> per hour 
per mile from shore, without approval from the Regional Supervisor;
    (2) For safety or air pollution prevention purposes, the Regional 
Supervisor may further restrict the flaring of gas containing 
H<INF>2</INF>S. The Regional Supervisor will use information provided 
in the lessee's H<INF>2</INF>S Contingency Plan (Sec.  250.490(f)), 
Exploration Plan, Development and Production Plan, Development 
Operations Coordination Document, and associated documents to determine 
the need for restrictions; and
    (3) If the Regional Supervisor determines that flaring at a 
facility or group of facilities may significantly affect the air 
quality of an onshore area, the Regional Supervisor may require you to 
conduct an air quality modeling analysis to determine the potential 
effect of facility emissions. The Regional Supervisor may require 
monitoring and reporting, or may restrict or prohibit flaring, under 
Sec. Sec.  250.303 and 250.304.
    (c) You must report flared and vented gas containing H<INF>2</INF>S 
as required under Sec.  250.1163. In addition, the Regional Supervisor 
may require you to submit monthly reports of flared and vented gas 
containing H<INF>2</INF>S. Each report must contain, on a daily basis:
    (1) The volume and duration of each flaring and venting occurrence;
    (2) H<INF>2</INF>S concentration in the flared or vented gas; and
    (3) The calculated amount of SO<INF>2</INF> emitted.

Enhanced Recovery


Sec.  250.1165  What must I do for enhanced recovery operations?

    (a) You must promptly initiate enhanced oil and gas recovery 
operations for all reservoirs where these operations would result in 
increased ultimate recovery of oil or gas under sound engineering and 
economic principles.
    (b) Before initiating enhanced recovery operations, you must submit 
a proposed plan to the Regional Supervisor and receive approval for 
pressure maintenance, secondary or tertiary recovery, cycling, and 
similar recovery operations intended to increase the ultimate recovery 
of oil and gas from a reservoir. The proposed plan must include, for 
each project reservoir, a brief geologic and engineering overview, 
structure map, well log section, Form MMS-127, and any additional 
information required by the Regional Supervisor.
    (c) You must report to Minerals Revenue Management the volumes of 
oil, gas, or other substances injected, produced, or produced for a 
second time under Sec.  216.53 of this title.

Special Alaska OCS Region Requirements


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

    (a) For any development in the Alaska OCS Region, you must submit 
an annual reservoir management report to the Regional Supervisor. The 
report must contain information detailing the activities performed 
during the previous year and planned for the upcoming year that will 
provide for:
    (1) The prevention of waste;
    (2) The protection of correlative rights; and
    (3) A greater ultimate recovery of oil and gas.
    (b) If your development is jointly regulated by MMS and the State 
of Alaska, MMS and the AOGCC will jointly determine appropriate 
reporting requirements to minimize or eliminate duplicate reporting 
requirements.
    (c) Every time you are required to submit Form MMS-127 under Sec.  
250.1155, you must request an MER for each producing sensitive 
reservoir in the Alaska OCS Region, unless otherwise instructed by the 
Regional Supervisor.

Information Needed With Forms and for Approvals


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

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

[[Page 9900]]



--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                            Production
                                                                                         Gas cap          Downhole         Reservoir      within 500-ft
                                                     WPT MMS-126      SRI MMS-127       production      commingling    reclassification    of a Unit or
                                                                                                                                            Lease Line
--------------------------------------------------------------------------------------------------------------------------------------------------------
(a) Maps:
    (1) Base map with surface, bottomhole, and     ...............  ...............         [check]          [check]   ................         [check]
     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         [check]          [check]          [check]          [check]           [check]          [check]
     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       ...............         [check]          [check]          [check]   ................  ...............
     penetrated for each well, identified at the
     penetration point...........................
    (4) Net hydrocarbon isopach with net feet of   ...............         [check]          [check]          [check]   ................  ...............
     pay for each well, identified at the
     penetration point...........................
(b) Seismic data:
    (1) Representative seismic lines, including    ...............  ...............         [check]          [check]   ................         [check]
     strike and dip lines that confirm the
     structure; indicate polarity................
    (2) Time/depth correlation table for seismic   ...............  ...............         [check]          [check]   ................         [check]
     data........................................
    (3) Amplitude extraction of seismic horizon,   ...............         [check]          [check]          [check]           [check]          [check]
     if applicable...............................
(c) Logs:
    (1) Well log sections with tops and bottoms           [check]          [check]          [check]          [check]           [check]          [check]
     of the reservoir(s) and proposed or existing
     perforations................................
    (2) Structural cross-sections showing the      ...............  ...............         [check]          [check]           [check]   ...............
     subject well and nearby wells...............
(d) Engineering Data:
    (1) Estimated recoverable reserves for each    ...............         [check]         [dagger]         [dagger]   ................         [check]
     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        ...............  ...............         [check]          [check]   ................         [check]
     proposed conditions.........................
    (3) The drive mechanism of each reservoir....  ...............         [check]          [check]          [check]           [check]          [check]
    (4) Pressure data, by date, and whether they   ...............  ...............         [check]          [check]           [check]   ...............
     are estimated or measured...................
    (5) Production data and decline curve          ...............  ...............         [check]          [check]           [check]   ...............
     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    ...............         [check]          [check]          [check]           [check]          [check]
     competitive as defined under Sec.   250.105.
    (3) Operator name, lessee name(s), block,      ...............  ...............  ...............         [check]   ................         [check]
     lease number, royalty rate, and unit number
     (if applicable) of all relevant leases......
    (4) Brief geologic overview of project.......  ...............  ...............         [check]          [check]           [check]          [check]
    (5) Explanation of why the proposed            ...............  ...............         [check]          [check]   ................         [check]
     completion scenario will not harm ultimate
     recovery....................................

[[Page 9901]]

 
    (6) List of all wells in subject reservoirs    ...............  ...............         [check]          [check]           [check]         [check]
     that have ever produced or been used for
     injection...................................
--------------------------------------------------------------------------------------------------------------------------------------------------------
[dagger] Each Gas Cap Production request and Downhole Commingling request should include the estimated recoverable reserves for (1) the case where your
  proposed production scenario is approved, and (2) the case where your proposed production scenario is denied.
* Additional items the Regional Supervisor may request.
Note: All maps must be at a standard scale and show lease and unit lines. If you have not generated all of the required data for your own purposes, you
  may submit those data you have available for consideration.

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

[FR Doc. E7-3846 Filed 3-5-07; 8:45 am]
BILLING CODE 4310-MR-P


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