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Federal Register / Vol. 72, No. 43 / Tuesday, March 6, 2007 / Proposed Rules
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TABLE 1.—AIRBUS SERVICE BULLETINS—Continued
Service Bulletin
Revision level
A320–27–1117 ....................................................................................................................................
Revision 03 ..............
General Visual Inspections
(j) For all airplanes: At the time specified
in paragraph (j)(1) or (j)(2) of this AD, as
applicable, do a general visual inspection of
the inboard flap trunnions for any wear
marks and of the sliding panels for any
cracking at the long edges, and do all
applicable corrective actions, by
accomplishing all of the applicable actions
specified in the Accomplishment
Instructions of Airbus Service Bulletin A320–
57–1133, Revision 01, dated August 7, 2006;
except as provided by paragraph (p) of this
AD. All corrective actions must be done at
the compliance times specified in Figures 5
and 6, as applicable, of the service bulletin;
except as provided by paragraphs (m), (n),
and (o) of this AD. Repeat the inspection
thereafter at intervals not to exceed 4,000
flight hours. Accomplishment of the general
visual inspection required by this paragraph
terminates the detailed inspection
requirement of paragraph (g) of this AD.
Note 3: For the purposes of this AD, a
general visual inspection is: ‘‘A visual
examination of an interior or exterior area,
installation, or assembly to detect obvious
damage, failure, or irregularity. This level of
inspection is made from within touching
distance unless otherwise specified. A mirror
may be necessary to ensure visual access to
all surfaces in the inspection area. This level
of inspection is made under normally
available lighting conditions such as
daylight, hangar lighting, flashlight, or
droplight and may require removal or
opening of access panels or doors. Stands,
ladders, or platforms may be required to gain
proximity to the area being checked.’’
(1) For airplanes on which the detailed
inspection required by paragraph (g) of this
AD has been done before the effective date
of this AD: Inspect before accumulating 4,000
total flight hours on the inboard flap
trunnion since new, or within 4,000 flight
hours after accomplishing the most recent
inspection required by paragraph (g) of this
AD, whichever occurs later.
(2) For airplanes other than those
identified in paragraph (j)(1) of this AD:
Inspect at the latest of the applicable times
specified in paragraphs (j)(2)(i), (j)(2)(ii), and
(j)(2)(iii) of this AD.
(i) Before accumulating 4,000 total flight
hours on the inboard flap trunnion since
new.
(ii) Within 4,000 flight hours after
accomplishing paragraph (f) or (h) of this AD.
(iii) Within 600 flight hours after the
effective date of this AD.
Actions Accomplished According to Previous
Issue of Service Bulletins
(k) Accomplishment of the modification
required by paragraph (f) of this AD before
the effective date of this AD, in accordance
with Airbus Service Bulletin A320–27–1117,
Revision 03, dated August 24, 2001, is
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acceptable for compliance with the
requirements of that paragraph.
(l) Accomplishment of the inspections
required by paragraph (j) of this AD before
the effective date of this AD, in accordance
with Airbus Service Bulletin A320–57–1133,
dated July 28, 2005, is acceptable for
compliance with the requirements of that
paragraph.
Compliance Times
Grace Period Assessment
(o) Where Airbus Service Bulletins A320–
57–1133, dated July 28, 2005; and Revision
01, dated August 7, 2006; specify contacting
the manufacturer for a grace period
assessment after replacing the trunnion or
flap, contact the Manager, International
Branch, ANM–116, Transport Airplane
Directorate, FAA; the Direction Ge´ne´rale de
l’Aviation Civile; or the European Aviation
Safety Agency (or its delegated agent); for the
grace period assessment.
No Reporting Requirement
(p) Although Airbus Service Bulletins
A320–57–1133, dated July 28, 2005; and
Revision 01, dated August 7, 2006; specify to
submit certain information to the
manufacturer, this AD does not include that
requirement.
Alternative Methods of Compliance (AMOCs)
(q)(1) The Manager, International Branch,
ANM–116, has the authority to approve
AMOCs for this AD, if requested in
accordance with the procedures found in 14
CFR 39.19.
(2) Before using any AMOC approved in
accordance with 14 CFR 39.19 on any
airplane to which the AMOC applies, notify
the appropriate principal inspector in the
FAA Flight Standards Certificate Holding
District Office.
Related Information
(r) French airworthiness directive F–2005–
139, dated August 3, 2005, also addresses the
subject of this AD.
Frm 00013
Fmt 4702
August 24, 2001.
Issued in Renton, Washington, on February
23, 2007.
Ali Bahrami,
Manager, Transport Airplane Directorate,
Aircraft Certification Service.
[FR Doc. E7–3841 Filed 3–5–07; 8:45 am]
BILLING CODE 4910–13–P
DEPARTMENT OF THE INTERIOR
(m) Where Airbus Service Bulletins A320–
57–1133, dated July 28, 2005; and Revision
01, dated August 7, 2006; specify replacing
the sliding panel at the next opportunity if
damaged, replace it within 600 flight hours
after the inspection required by paragraph (g)
or (j) of this AD, as applicable.
(n) If any damage to the trunnion is found
during any inspection required by paragraph
(g) or (j) of this AD, before further flight, do
the corrective actions specified in Airbus
Service Bulletin A320–57–1133, dated July
28, 2005; or Revision 01, dated August 7,
2006. As of the effective date of this AD, only
Revision 01 may be used.
PO 00000
Date
Sfmt 4702
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
Minerals Management Service
(MMS), Interior.
ACTION: Proposed rule.
AGENCY:
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.
• MMS’s Public Connect on-line
commenting system, https://
ocsconnect.mms.gov. Follow the
instructions on the Web site for
submitting comments.
• Federal eRulemaking Portal: http://
www.regulations.gov. Follow the
instructions on the Web site for
submitting comments.
• E-mail MMS at
rules.comments@mms.gov. Use RIN
1010–AD12 in the subject line.
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• Fax: 703–787–1546. Identify with
the RIN, 1010–AD12.
• Mail or hand-carry comments to the
Department of the Interior; Minerals
Management Service; Attention: Rules
Processing Team (RPT); 381 Elden
Street, MS–4024; Herndon, Virginia
20170–4817. Please reference ‘‘Oil and
Gas Production Requirements, 1010–
AD12’’ in your comments and include
your name and return address.
• Send comments on the information
collection in this rule to: Interior Desk
Officer 1010–AD12, Office of
Management and Budget; 202/395–6566
(facsimile); e-mail:
oira_docket@omb.eop.gov.
FOR FURTHER INFORMATION CONTACT:
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:
• The amount of gas emitted through
flaring and venting worldwide is small
compared with global natural gas
production and represents a small
portion of greenhouse gas emissions.
• Worldwide flaring and venting is
estimated to contribute, respectively,
about 4 percent of the total methane and
about 1 percent of the total carbon
dioxide emissions caused by human
activity.
• EIA [Energy Information
Administration] estimates that the
United States flares or vents about 0.4
percent of its production, representing
only 3 percent of the world’s total
amount of natural gas flared and vented.
• In the United States, there are welldeveloped natural gas markets and
infrastructure to reduce the flaring and
venting of associated natural gas.
• Since 1990, the quantity of oil
produced has increased, but because of
various global reduction initiatives, the
quantity of natural gas flared and vented
has remained constant. Consequently,
natural gas emissions as a percentage of
oil production have decreased.
• Since the impact of methane
(venting) on the earth’s atmosphere is
about 23 times greater than that of
carbon dioxide (flaring), a small change
in the ratio of flaring to venting could
cause a disproportionate change in the
impact of emissions.
The report concluded that more
accurate records on flaring and venting
are needed to determine the amount of
the resource that is lost and the volume
of greenhouse gas emissions these
practices contribute to the atmosphere
each year. The GAO made two
recommendations to the Secretary of the
Interior: (1) ‘‘Consider the cost and
benefit of requiring that companies flare
the natural gas, whenever possible,
when flaring or venting is necessary,’’
and (2) ‘‘consider the cost and benefit of
requiring that companies use flaring and
venting meters to improve oversight.’’ In
addition, there was a recommendation
to the Secretary of Energy to consider,
‘‘in consultation with EPA
[Environmental Protection Agency],
MMS, and BLM [Bureau of Land
Management], how to best collect
separate statistics on flaring and
venting.’’
In comments on the draft report, the
Department of the Interior (DOI)
concurred with the report’s
recommendations and agreed to assess
the cost effectiveness of requiring the oil
and gas industry to implement these
changes. MMS conducted analyses to
assess the costs and benefits of requiring
flare/vent meters and also of requiring
flaring instead of venting. The first
analysis supported the recommendation
to require meters provided that the
Current rule
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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 § 250.1150
instead of § 250.1100 to accommodate
other planned rulemaking. The
proposed structure is shown in the
following table:
Proposed rule
§ 250.1100 Definitions for production rates ...........................................
§ 250.105 Definitions.
§ 250.1101 General requirements and classification of reservoirs ........
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§ 250.105
Definitions.
§ 250.1150 General reservoir production requirements.
§ 250.1154 How do I determine if my reservoir is sensitive?
§ 250.1155 What information must I submit for sensitive reservoirs?
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Current rule
Proposed rule
§ 250.1102
Oil and gas production rates ...............................................
§ 250.1103
Well production testing ........................................................
§ 250.1104
Bottomhole pressure survey ...............................................
§ 250.1105
Flaring or venting of gas and burning liquid hydrocarbons
§ 250.1106
Downhole commingling .......................................................
§ 250.1107 Enhanced oil and gas recovery operations ........................
New ...........................................................................................................
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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
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§ 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?
Requirements for production rates are largely eliminated. Portions retained were combined with new information in ‘‘§ 250.1159 May the
Regional Supervisor limit my well or reservoir production rates?’’
§ 250.1151 How often must I conduct well production tests?
§ 250.1152 How do I conduct well tests?
§ 250.1153 When must I conduct a static bottomhole pressure survey?
§ 250.1160 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 and liquid hydrocarbon burning volumes and what records must I maintain?
§ 250.1164 What are the requirements for flaring or venting gas containing H2S?
§ 250.1158 How do I receive approval to downhole commingle hydrocarbons?
§ 250.1165 What must I do for enhanced recovery operations?
§ 250.1159 May the Regional Supervisor limit my well or reservoir
production rates?
§ 250.1166 What additional reporting is required for developments in
the Alaska Region?
§ 250.1167 What information must I submit for approvals?
without significant detriment to efforts
for conservation and maximization of
ultimate recovery. However, the
proposed rule would allow the Regional
Supervisor to set production rates in
cases where excessive production could
harm ultimate recovery from the
reservoir.
The proposed rule would clarify
required information submittals to
MMS, including requirements relating
to the documents submitted to MMS
and the timing of those submissions. For
example, there is additional guidance
on notifying adjoining operators
regarding production within 500 feet of
a common lease or unit line. The
proposed rule would provide more
detail as to when the notification must
occur, what the notice must include,
and how to verify the notification with
MMS.
The proposed rule would incorporate
several Notices to Lessees and Operators
(NTLs) that clarify the current
regulations. These NTLs would be
obsolete if the proposed rule becomes
final and MMS would withdraw all of
these NTLs at that time. However, if
necessary, MMS would issue additional
NTLs to provide guidance. The NTLs
affected include:
• NTL No. 97–16, ‘‘Production
Within 500 Feet of a Unit or Lease
Line,’’ effective August 1, 1997. This
NTL clarifies MMS policy on issuing
approvals for production within 500 feet
of a unit or lease line, and includes
details on what the requesting operator
needs to provide to MMS for approval.
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Those details are addressed in the
proposed rule.
• NTL No. 98–23, ‘‘Interim Reporting
Requirements for 30 CFR 250, subpart
K, Oil and Gas Production Rates,’’
effective October 15, 1998. This NTL
addressed oral approvals for gas flaring
and relaxed some of the requirements
regarding production rates, including
MER and MPR in certain circumstances.
The NTL clarified the submittal of
written summary letters on flaring
incidents that received oral approval.
These requirements are addressed in the
proposed rule.
• NTL No. 99–G20, ‘‘Downhole
Commingling Applications,’’ effective
September 7, 1999. This NTL was
issued in conjunction with NTL No. 99–
G19. It clarifies what information the
applicant needs to include in downhole
commingling applications to ensure that
the application is processed without
delay. These information requirements
were added to the proposed rule.
• NTL No. 2006–N06, ‘‘Flaring and
Venting Approvals,’’ effective December
19, 2006. This NTL clarifies the
definitions of flaring and venting, the
record-keeping requirements, the
classification of emitted natural gas, and
the MMS policy regarding continuous
flaring or venting of small volumes of
oil-well gas or gas-well gas from storage
vessels or other low-pressure
production vessels when the gas cannot
be economically recovered. These issues
are addressed in the proposed rule. This
NTL also provides contact information
for each Region and provides sample
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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 worldwide 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-bysection description of the substantive
proposed changes to subpart K:
§ 250.105 Definitions. In the current
rule, definitions appear in subpart A at
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30 CFR 250.105 and in subpart K at 30
CFR 250.1100. MMS proposes removing
the definitions from subpart K because
they already appear in subpart A.
General
§ 250.1150 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
§ 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 halfyear. This would allow operators to
submit all their well tests at one time
and include the most recent tests for
those few completions that produced
during the 6-month period, but were not
tested within the last 45 days.
§ 250.1152 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.
§ 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.
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Classifying Reservoirs
§ 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.
§ 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
§ 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.
§ 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.
§ 250.1158 How do I receive
approval to downhole commingle
hydrocarbons? This section would
address how to obtain MMS approval to
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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.
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Production Rates
§ 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
§ 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 oilwell gas for flaring and venting approval
purposes.
The proposed rule would require
operators to receive approval before
flaring or venting gas in volumes higher
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than those specified in their previouslyapproved plans. This would enable
MMS to ensure that flaring and venting
activities are in compliance with
environmental laws.
The proposed rule would also allow
the Regional Supervisor to specify
flaring and venting volume limits (in
addition to time limits) in order to
prevent air quality degradation or the
loss of reserves. This is sometimes
necessary because offshore production
facilities are now capable of flaring or
venting extremely large volumes in a
short amount of time.
§ 250.1161 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
§ 250.1160.
§ 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.
§ 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
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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
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pursue civil penalties, under 30 CFR
250 subpart N—Outer Continental Shelf
(OCS) Civil Penalties, if we determine
that the loss was avoidable or due to
negligence.
§ 250.1164 What are the
requirements for flaring or venting gas
containing H2S? The proposed rule
would require Regional Supervisor
approval before emitting more than 15
lbs of SO2 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.
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.
Enhanced Recovery
§ 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.
Information Needed With Forms and for
Approvals
§ 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.
Special Alaska OCS Region
Requirements
§ 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
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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
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9889
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.
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(4) This proposed rule would not raise
novel legal or policy issues. There are
some changes in production
requirements in this proposal, but most
of the changes clarify existing MMS
requirements. Some may require
additional paperwork for the operators.
Since the basic production requirements
are not changed, and restrictions on
production rates are decreased, this
proposed rule should not raise novel
legal or policy issues.
Regulatory Flexibility Act (RFA)
The Department of the Interior
certifies that this proposed rule would
not have a significant economic effect
on a substantial number of small entities
as defined under the RFA (5 U.S.C. 601
et seq.). An initial Regulatory Flexibility
Analysis is not required. Accordingly, a
Small Entity Compliance Guide is not
required.
This rule applies to all lessees
operating on the OCS. Lessees fall under
the Small Business Administration’s
North American Industry Classification
System (NAICS) code 211111, Crude
Petroleum and Natural Gas Extraction.
Under this NAICS code, companies with
less than 500 employees are considered
small businesses. MMS estimates that
130 lessees explore for and produce oil
and gas on the OCS; approximately 70
percent of them (91 companies) fall into
the small business category. The
proposed regulation would therefore
affect a substantial number of small
entities. However, we have determined
that it would not have a significant
economic effect on these small entities.
One new requirement that would
impose a cost to operators is a
requirement to install flaring/venting
meters on all facilities that process more
than 2,000 BOPD. The GAO report on
flaring and venting natural gas, released
in July 2004, recommended that MMS
require these meters to improve
oversight. MMS agrees with this
recommendation. MMS regulations
allow flaring and venting in very limited
circumstances. These meters would
help MMS:
• Verify the amounts of natural gas
that operators flare or vent into the
environment;
• Prevent waste of resources;
• Collect the proper royalties on
avoidably flared or vented gas;
• Determine if an operator is violating
MMS regulations; and
• Assess the impacts on the
environment.
In determining the criteria for which
facilities must install the meters, MMS
considered the cost of the meters and
the amount of production needed to
justify the cost. To ensure that the
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requirement to install flare/vent meters
would not produce an undue burden on
small companies, it was limited to those
facilities that process more than an
average of 2,000 BOPD.
MMS estimates that 34 companies
would have to install meters on 112
facilities at an average cost of $77,000
per facility and a total cost to industry
of $8,624,000 (112 × $77,000 =
$8,624,000). Of those, nine companies
are considered small businesses, based
on the NAICS. These nine companies
represent only 7 percent of the 130
operators on the OCS. We estimate that
seven of these nine companies would
need to install meters on one facility
each; one company would need to
install meters on two facilities; and one
company would need to install meters
on three facilities. This represents an
average cost of $105,875 for each of the
small companies (11 facilities ×
$77,000/9 companies). The average cost
to non small companies would be
$311,080 per company (101 facilities ×
$77,000/25 companies). In addition, this
does not represent an unfair burden to
small companies because the cost of
these meters is small in comparison to
the revenues generated by the amount of
oil processed by those facilities.
Your comments are important. The
Small Business and Agriculture
Regulatory Enforcement Ombudsman
and 10 Regional Fairness Boards were
established to receive comments from
small businesses about Federal agency
enforcement actions. The Ombudsman
will annually evaluate the enforcement
activities and rate each agency’s
responsiveness to small business. If you
wish to comment on the actions of
MMS, call 1–888–734–3247. You may
comment to the Small Business
Administration without fear of
retaliation. Disciplinary action for
retaliation by an MMS employee may
include suspension or termination from
employment with the DOI.
Small Business Regulatory Enforcement
Fairness Act (SBREFA)
The proposed rule is not a major rule
under SBREFA (5 U.S.C. 804(2)). This
proposed rule:
a. Would not have an annual effect on
the economy of $100 million or more.
This proposed rule revises the
requirements for oil and gas production.
The changes would not have an impact
on the economy or an economic sector,
productivity, jobs, the environment, or
other units of government. Most of the
new requirements are paperwork
requirements, and would not add
significant time to development and
production processes. One new
requirement would add new costs for
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some operators. Operators would be
required to install flare/vent meters on
any facility that processes more than an
average of 2,000 BOPD. MMS estimates
that 34 companies would have to install
meters on 112 facilities at an average
cost of $77,000 per facility and a total
cost to industry of $8,624,000 (112 ×
$77,000 = $8,624,000).
b. Would not cause a major increase
in costs or prices for consumers,
individual industries, Federal, State, or
local government agencies, or
geographic regions.
In most cases, this proposed rule
would eliminate the requirement for
operators to set limits on production
rates, allowing the operators to
determine the best rate to produce their
reservoirs. The limits on burning,
flaring, and venting are clearer. These
limits would encourage conservation of
our natural resources, without putting
undue production restrictions on
operators. There would be a new
requirement to install meters on
facilities that process more than an
average of 2,000 BOPD. As discussed
above, this requirement would not
significantly increase the cost of doing
business offshore.
c. Would not have significant adverse
effects on competition, employment,
investment, productivity, innovation, or
the ability of U.S.-based enterprises to
compete with foreign-based enterprises.
This proposed rule would eliminate the
requirement for operators to set limits
on production rates, allowing the
operators to determine the best rate to
produce their reservoirs. There are
clearer limits on burning, flaring, and
venting, which would encourage
conservation of our natural resources.
Unfunded Mandates Reform Act
(UMRA) of 1995
This proposed rule would not impose
an unfunded mandate on State, local, or
tribal governments or the private sector
of more than $100 million per year. The
proposed rule would not have a
significant or unique effect on State,
local, or tribal governments or the
private sector. A statement containing
the information required by UMRA (2
U.S.C. 1531 et seq.) is not required. This
is because the proposal would not affect
State, local, or tribal governments, and
the effect on the private sector is small.
Takings Implication Assessment
(Executive Order 12630)
The proposed rule is not a
governmental action capable of
interference with constitutionally
protected property rights. Thus, MMS
did not need to prepare a Takings
Implication Assessment according to
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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.
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Paperwork Reduction Act (PRA)
The proposed rule contains a
collection of information that has been
submitted to OMB for review and
approval under § 3507(d) of the PRA. As
part of our continuing effort to reduce
paperwork and respondent burdens,
MMS invites the public and other
Federal agencies to comment on any
aspect of the reporting and
recordkeeping burden. You may submit
your comments on the information
collection aspects of this proposed rule
directly to the Office of Management
and Budget (OMB), Office of
Information and Regulatory Affairs,
OMB Attention: Desk Officer for the
Department of the Interior via OMB email: (OIRA_DOCKET@omb.eop.gov); or
by fax (202) 395–6566; identify with
1010–AD12. Send a copy of your
comments to the Rules Processing Team
(RPT), Attn: Rules Comments; 381 Elden
Street, MS–4024; Herndon, Virginia
20170–4817. Please reference ‘‘Oil and
Gas Production Requirements—AD12’’
9891
minor changes to the information
collection burden. The changes are:
• Report to Minerals Revenue
Management (MRM) measured gas
flaring or venting and liquid
hydrocarbon burning. Submit periodic
reports of volumes of oil, gas, or other
substances injected, produced, or
produced for a second time. Both
requirements and burdens are now
reported to MRM and their respective
burdens are covered under OMB Control
Number 1010–0139 (–154 burden
hours);
• Request Regional Supervisor
approval for emitting more than 15 lbs.
of SO2 (+10 burden hours);
• Submit to Regional Supervisor air
quality modeling analysis report. The
proposed burden hours represent an
adjustment to a current requirement for
information that was not previously
collected (+40 burden hours);
• For Alaska Region Only: Submit to
Regional Supervisor annual reservoir
management report and supporting
information. (At this time, the state
requires the same information and MMS
receives a copy). Alaska has started
producing in state waters. If new
development occurs in Federal waters, a
minimal burden for submitting an
annual reservoir management report,
and burden hours for annual revisions
are being added (+161 burden hours).
• Maintain meter records for detailing
gas flaring or venting, and liquid
hydrocarbon burning for 6 years. These
new burden requirements do not add
additional burden hours.
• General departure or alternative
compliance requests (+5 burden hours).
The currently approved information
collection for this subpart (1010–0041)
will be superseded by this collection
when final regulations take effect.
Currently, regulations covered under
OMB Control Number 1010–0041 have
43,065 annual burden hours. MMS
estimates the total annual reporting and
recordkeeping ‘‘hour’’ burden for the
proposed rule to be 43,127 hours; this
is an increase of 62 burden hours. With
the exception of the recordkeeping
requirement changes and the items
identified as ‘‘new’’ in the following
chart, the burden estimates shown are
those that are estimated for the current
subpart K regulations.
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
Fee/non-hour cost
30 CFR 250 Subpart K
Reporting & recordkeeping requirement
Average number of
annual responses
Hour burden
1151(a), (c); 1155; 1165;
1166(c); 1167.
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Annual burden
hours
Submit form MMS–126 and supporting information ..
3
1,325 forms ......................
3,975
Submit form MMS–127 and supporting information ..
2.2
2,189 forms ......................
4,816
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Fee/non-hour cost
30 CFR 250 Subpart K
Reporting & recordkeeping requirement
Average number of
annual responses
Hour burden
1151(b) ..............................
1152(b), (c) .......................
1152(d) ..............................
1153 ..................................
1154; 1167 ........................
1156; 1167 ........................
Submit form MMS–128 and supporting information ..
0.1—3
Request extension of time to submit results of semiannual well test.
Obtain Regional Supervisor approval to conduct well
testing using alternative procedures; conduct
tests/retests to establish proper MPR or MER;
conduct multipoint backpressure test for open flow
potential.
Provide advance notice of time and date of well
tests.
Submit results of all static bottomhole pressure surveys obtained by lessee using form MMS–140.
Request departure requirement w/justification to
Regional Supervisor; submit with Form MMS–140
and supporting information.
Request reclassification of reservoir for Regional
Supervisor approval and submit supporting information.
Request approval to produce within 500 feet of a
unit or lease line and submit supporting information; notify operators; provide proof of date to Regional Supervisor.
Annual burden
hours
1,336*
0.5
13,000 GOM forms ..........
600 POCS forms
37 requests ......................
0.5
37 requests ......................
19
0.5
10 notices ........................
5
14
1
1,270 surveys ..................
120 survey waivers ..........
17,780
120
6
20 requests ......................
120
5
50 requests ......................
250
19
3,300 × 50 requests = $165,000
1157; 1167 ........................
Request approval to produce gas cap of a sensitive
reservoir and submit supporting information; obtain approval to produce gas from an oil reservoir
with an associated gas cap.
12
125 requests ....................
1,500
$4,200 × 125 requests = $525,000
1158; 1167 ........................
Submit request to downhole commingle hydrocarbons and supporting information; notify operators; provide proof of date to Regional Supervisor.
6
119 applications ...............
714
$4,900 × 119 applications = $583,100
1160; 1161 ........................
Request Regional Supervisor approval/inform to
flare or vent oil-well gas or gas-well gas/exceed
volume; submit documentation.
0.5
1,007 requests .................
504
1162; 1163(e) ....................
Request approval to burn produced liquid hydrocarbons; submit documentation.
Initial purchase and install gas meters to measure
the amount of gas flared or vented. This is a nonhour cost burden.
0.5
60 requests ......................
30
0
112 ...................................
0
NEW 1163 .........................
cprice-sewell on PROD1PC67 with PROPOSALS
112 meters @ $77,000 ea = $8,624,000
NEW 1163(b); 1165(c) ......
Report to MRM measured gas flaring or venting and liquid hydrocarbon burning—burden covered
under 1010–0139
NEW 1164(b)(1) ................
Request Regional Supervisor approval for emitting
more than 15 lbs. of SO2.
1164(b)(2) .........................
H2S Contingency, Exploration, or Development and Production Plans—burden covered under
1010–0141 and 1010–0151
NEW 1164(b)(3) ................
Submit to Regional Supervisor air quality modeling
analysis.
Submit monthly reports of flared or vented gas containing H2S.
Submit proposed plan for enhanced recovery operations.
1164(c) ..............................
1165 ..................................
1165(c) ..............................
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0.5
20 requests ......................
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10
0
40
1 modeling analysis .........
40
2
3 operators × 12 mos. =
36.
27 plans ...........................
72
12
Submit periodic reports of volumes of oil, gas, or other substances injected, produced, or produced for a second time—burden covered under OMB approval 1010–0139
18:12 Mar 05, 2007
0
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Federal Register / Vol. 72, No. 43 / Tuesday, March 6, 2007 / Proposed Rules
9893
Fee/non-hour cost
30 CFR 250 Subpart K
Reporting & recordkeeping requirement
Average number of
annual responses
Hour burden
NEW 1166 .........................
Alaska Region only: submit to Regional Supervisor
annual reservoir management report and supporting information.
1
100
NEW 1150–1167 ...............
20
1
1163(c) ..............................
1
100
3 annual revisions ...........
5 .......................................
60
5
20,175 ..............................
31,800
13
869 platforms ...................
11,297
0.5
60 occurrences ................
30
Recordkeeping Subtotal
929 ...................................
11,327
Total Burden
21,104 ..............................
43,127
General departure or alternative compliance requests not specifically covered elsewhere in subpart K.
Reporting Subtotal
1163(c), (d) .......................
1 (required by State,
MMS gets copy).
1 new develop not State
lands.
Annual burden
hours
Maintain records for 6 years detailing gas flaring or
venting; maintain meter records and provide copies if requested.
Maintain records for 6 years detailing liquid hydrocarbon burning; maintain meter records and provide copies if requested.
$9,897,100
cprice-sewell on PROD1PC67 with PROPOSALS
* 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 (§ 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
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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.’’
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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:
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(1) Are the requirements in the
proposed rule clearly stated?
(2) Does the proposed rule contain
technical language or jargon that
interferes with its clarity?
(3) Does the format of the proposed
rule (grouping and order of sections, use
of headings, paragraphs, etc.) aid or
reduce its clarity?
(4) Is the description of the proposed
rule in the ‘‘Supplementary
Information’’ section of this preamble
helpful in understanding the rule?
Send a copy of any comments that
concern how we could make this
proposed rule easier to understand to:
Office of Regulatory Affairs; Department
of the Interior, Room 7229; 1849 C
Street, NW., Washington, DC 20240.
You may also e-mail the comments to
this address: Exsec@ios.doi.gov.
protection, Government contracts,
Investigations, Oil and gas exploration,
Penalties, Pipelines, Public lands—
mineral resources, Public lands—rightsof-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:
List of Subjects in 30 CFR Part 250
Authority: 43 U.S.C. 1331 et seq.; 31 U.S.C.
9701.
Continental shelf, Environmental
impact statements, Environmental
2. Amend § 250.105 to revise the
definition of ‘‘Sensitive reservoir’’ and
add in alphabetical order definitions for
‘‘Flaring’’ and ‘‘Venting’’ to read as
follows:
§ 250.105
Definitions.
*
*
*
*
*
Flaring means the burning of gas in
the field as it is released into the
atmosphere.
*
*
*
*
*
Sensitive reservoir means a reservoir
in which high reservoir production rates
will decrease ultimate recovery.
*
*
*
*
*
Venting means the release of gas into
the atmosphere without igniting it. This
includes gas that is released underwater
and bubbles to the atmosphere.
*
*
*
*
*
3. In § 250.125, revise the table in
paragraph (a) to read as follows:
§ 250.125
Service fees.
(a) * * *
SERVICE FEE TABLE
Service—processing of the following:
Fee amount
Change in Designation of Operator ...................
Suspension of Operations/Suspension of Production (SOO/SOP) Request.
Exploration Plan (EP) .........................................
Development and Production Plan (DPP) or
Development Operations Coordination Document (DOCD).
Deepwater Operations Plan ...............................
Conservation Information Document ..................
Application for Permit to Drill (APD; Form
MMS–123).
$150 .................................................................
$1,800 ..............................................................
§ 250.143.
§ 250.171.
$3,250 for each surface location, no fee for
revisions.
$3,750 for each well proposed, no fee for revisions.
§ 250.211.
$3,150 ..............................................................
$24,200 ............................................................
$1,850.
§ 250.292(p).
§ 250.296(a).
Initial applications only, no fee for revisions
§ 250.410(d);
§ 250.411;
§ 250.460;
§ 250.513(b);
§ 250.515;
§ 250.1605;
§ 250.1617(a); § 250.1622.
§ 250.460;
§ 250.465(b);
§ 250.513(b);
§ 250.515;
§ 250.613(b);
§ 250.615;
§ 250.1618(a); § 250.1622; § 250.1704(g).
Application for Permit to Modify (APM; Form
MMS–124).
$110 .................................................................
New Facility Production Safety System Application for facility with more than 125 components.
$4,750.
New Facility Production Safety System Application for facility with 25–125 components.
cprice-sewell on PROD1PC67 with PROPOSALS
30 CFR citation
New Facility Production Safety System Application for facility with fewer than 25 components.
Production Safety System Application—Modification with more than 125 components reviewed.
Production Safety System Application—Modification with 25–125 components reviewed.
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§ 250.241(e).
A component is a piece of equipment or ancillary system that is protected by one or
more of the safety devices required by API
RP 14C (incorporated by reference as
specified in § 250.198)
(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)
$1,150 ..............................................................
(Additional fee of $7,850 will be charged if
MMS deems it necessary to visit a facility
offshore; and $4,500 to visit a facility in a
shipyard)
$570 .................................................................
§ 250.802(e).
$530 .................................................................
§ 250.802(e).
$190 .................................................................
§ 250.802(e).
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§ 250.802(e).
§ 250.802(e).
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9895
SERVICE FEE TABLE—Continued
Service—processing of the following:
Fee amount
Production Safety System Application—Modification with fewer than 25 components reviewed.
Platform Application—Installation—under the
Platform Verification Program.
Platform Application—Installation—Fixed Structure Under the Platform Approval Program.
Platform
Application—Installation—Caisson/
Well Protector.
Platform Application—Modification/Repair .........
New Pipeline Application (Lease Term) .............
Pipeline Application—Modification (Lease Term)
Pipeline Application—Modification (ROW) .........
Pipeline Repair Notification ................................
Pipeline Right-of-Way (ROW) Grant Application
Pipeline Conversion of Lease Term to ROW .....
Pipeline ROW Assignment .................................
500 Feet From Lease/Unit Line Production Request.
Gas Cap Production Request ............................
Downhole Commingling Request .......................
Complex Surface Commingling and Measurement Application.
Simple Surface Commingling and Measurement
Application.
Voluntary Unitization Proposal or Unit Expansion.
Unitization Revision ............................................
Application to Remove a Platform or Other Facility.
Application to Decommission a Pipeline (Lease
Term).
Application to Decommission a Pipeline (ROW)
$80 ...................................................................
§ 250.802(e).
$19,900 ............................................................
§ 250.905(k).
$2,850 ..............................................................
§ 250.905(k).
$1,450 ..............................................................
§ 250.905(k).
$3,400 ..............................................................
$3,100 ..............................................................
$1,800 ..............................................................
$3,650 ..............................................................
$340 .................................................................
$2,350 ..............................................................
$200 .................................................................
$170 .................................................................
$3,300 ..............................................................
§ 250.905(k).
§ 250.1000(b).
§ 250.1000(b).
§ 250.1000(b).
§ 250.1008(e).
§ 250.1015.
§ 250.1015.
§ 250.1018.
§ 250.1156.
$4,200 ..............................................................
$4,900 ..............................................................
$3,550 ..............................................................
§ 250.1157.
§ 250.1158.
§ 250.1202(a); § 250.1203(b); § 250.1204(a).
$1,200 ..............................................................
§ 250.1202(a); § 250.1203(b); § 250.1204(a).
$10,700 ............................................................
§ 250.1303.
$760 .................................................................
$4,100 ..............................................................
§ 250.1303.
§ 250.1727.
$1,000 ..............................................................
§ 250.1751(a) or § 250.1752(a).
$1,900 ..............................................................
§ 250.1751(a) or § 250.1752(a).
Subpart K—Oil and Gas Production
Requirements
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?
General
Production Rates
Sec.
250.1150 What are the general reservoir
production requirements?
250.1159 May the Regional Supervisor limit
my well or reservoir production rates?
Well Tests and Surveys
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 H2S?
*
*
*
*
*
4. Revise subpart K to read as follows:
Flaring, Venting, and Burning Hydrocarbons
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
cprice-sewell on PROD1PC67 with PROPOSALS
30 CFR citation
250.1156 What steps must I take to receive
approval to produce within 500 feet of a
unit or lease line?
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
§ 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
§ 250.1151 How often must I conduct well
production tests?
(a) You must conduct well production
tests as shown in the following table:
You must conduct:
And you must submit to the Regional Supervisor:
(1) A well-flow potential test on all new, recompleted, or reworked well
completions within 30 days of the date of first continuous production.
Form MMS–126, Well Potential Test Report, along with the supporting
data as listed in the table in § 250.1167, within 15 days after the end
of the test period.
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You must conduct:
And you must submit to the Regional Supervisor:
(2) At least one well test during a calendar half-year for each producing
completion.
Results on Form MMS–128, Semiannual Well Test Report, of the most
recent well test obtained. This must be submitted within 45 days
after the end of the calendar half-year
(b) You may request an extension
from the Regional Supervisor if you
cannot submit the results of a
semiannual well test within the
specified time.
(c) You must submit an original and
one copy of the form required by
paragraph (a) of this section, as listed in
the table in § 250.1167. You must
include one public information copy
with each submittal in accordance with
§§ 250.190 and 250.196, and mark that
copy ‘‘Public Information.’’
§ 250.1152
How do I conduct well tests?
(a) When you conduct well tests you
must:
(1) Recover fluid from the well
completion equivalent to the amount of
fluid introduced into the formation
during completion, recompletion,
reworking, or treatment operations
before you start a well test;
(2) Produce the well completion
under stabilized rate conditions for at
least 6 consecutive hours before
beginning the test period;
(3) Conduct the test for at least 4
consecutive hours;
(4) Adjust measured gas volumes to
the standard conditions of 14.73 pounds
per square inch absolute (psia) and 60°F
for all tests; and
(5) Use measured specific gravity
values to calculate gas volumes.
(b) You may request approval from
the Regional Supervisor to conduct a
well test using alternative procedures if
you can demonstrate test reliability
under those procedures.
(c) The Regional Supervisor may also
require you to conduct the following
§ 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.
Annual static bottomhole pressure surveys in a sufficient number of
key wells to establish an average reservoir pressure. The Regional
Supervisor may require that bottomhole pressure surveys be performed on specific wells.
(2) A reservoir with three or more producing completions ......................
cprice-sewell on PROD1PC67 with PROPOSALS
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.
(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.
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Classifying Reservoirs
§ 250.1154 How do I determine if my
reservoir is sensitive?
(a) You must determine whether each
reservoir is sensitive. You must classify
the reservoir as sensitive if:
(1) Under initial conditions it is an oil
reservoir with an associated gas cap;
(2) At any time there are near-critical
fluids; or
(3) The reservoir is undergoing
secondary or tertiary recovery.
(b) For the purposes of this subpart,
near-critical fluids are those fluids that
occur in high temperature, highpressure 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
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information, as listed in the table in
§ 250.1167, with your request.
(e) If information indicates that a
reservoir previously classified as
sensitive is now non-sensitive, you may
submit a request to the Regional
Supervisor to reclassify the reservoir.
You must include supporting
information, as listed in the table in
§ 250.1167, with your request.
§ 250.1155 What information must I submit
for sensitive reservoirs?
You must submit an original and
three copies of Form MMS–127 and
supporting information, as listed in the
table in § 250.1167 to the Regional
Supervisor. You must include one
public information copy with each
submittal in accordance with §§ 250.190
and 250.196, and mark that copy
‘‘Public Information.’’ You must submit
this information:
(a) Within 45 days after beginning
production from the reservoir or
discovering that it is sensitive;
(b) At least once during the calendar
year;
(c) Within 45 days after you revise
reservoir parameters; and
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(d) Within 45 days after the Regional
Supervisor classifies the reservoir as
sensitive under § 250.1154(c).
Approvals Prior to Production
§ 250.1156 What steps must I take to
receive approval to produce within 500 feet
of a unit or lease line?
cprice-sewell on PROD1PC67 with PROPOSALS
(a) You must obtain approval from the
Regional Supervisor before you start
producing from a well that has any
portion of the completed interval less
than 500 feet from a unit or lease line.
Submit to MMS the service fee listed in
§ 250.125 and the Regional Supervisor
will determine whether approval of
your request will maximize ultimate
recovery, avoids the waste of natural
resources or whether it is necessary to
protect correlative rights. You do not
need to obtain approval if the adjacent
leases or units have the same unit, lease,
and royalty interests as the lease or unit
you plan to produce. You do not need
to obtain approval if the adjacent block
is unleased.
(b) You must notify the operator(s) of
adjacent property(ies) that are within
500 feet of the completion, if the
adjacent acreage is a leased block in the
Federal OCS. You must provide the
Regional Supervisor proof of the date of
the notification. The operators of the
adjacent properties have 30 days after
receiving the notification to provide the
Regional Supervisor letters of
acceptance or objection. If an adjacent
operator does not respond within 30
days, the Regional Supervisor will
presume there are no objections and
proceed with a decision. The
notification must include:
(1) The well name;
(2) The rectangular coordinates (x, y)
of the location of the top and bottom of
the completion or target completion
reference to the North American Datum
1983, and the subsea depths of the top
and bottom of the completion or target
completion;
(3) The distance from the completion
or target completion to the unit or lease
line at its nearest point; and
(4) A statement indicating whether or
not it will be a high-capacity completion
having a perforated or open hole
interval greater than 150 feet measured
depth.
§ 250.1157 How do I receive approval to
produce gas from an oil reservoir with an
associated gas cap?
You must request and receive written
approval from the Regional Supervisor
before producing gas from each
completion in an oil reservoir that is
known to have an associated gas cap. If
the oil reservoir is not initially known
to have an associated gas cap, but your
oil well begins to show characteristics of
a gas well, you must request and receive
written approval from the Regional
Supervisor to continue producing the
well. You must include the service fee
listed in § 250.125 and the supporting
information, as listed in the table in
§ 250.1167, with your request.
§ 250.1158 How do I receive approval to
downhole commingle hydrocarbons?
(a) Before you perforate a well, you
must request and receive approval from
the Regional Supervisor to commingle
hydrocarbons produced from multiple
reservoirs within a common wellbore.
The Regional Supervisor will determine
whether your request maximizes
ultimate recovery and avoids the waste
of natural resources. You must include
the service fee listed in § 250.125 and
the supporting information, as listed in
the table in § 250.1167, with your
request.
(b) If one or more of the commingled
reservoirs is a competitive reservoir, you
must notify the operators of all leases
that contain the reservoir that you
9897
intend to downhole commingle the
reservoirs. Your request for approval of
downhole commingling must include
proof of the date of this notification. The
notified operators have 30 days after
notification to provide the Regional
Supervisor with letters of acceptance or
objection. If the notified operators do
not respond within the specified period,
the Regional Supervisor will assume the
operators do not object and proceed
with a decision.
Production Rates
§ 250.1159 May the Regional Supervisor
limit my well or reservoir production rates?
(a) The Regional Supervisor may set a
Maximum Production Rate (MPR) for a
producing well completion, or set a
Maximum Efficient Rate (MER) for a
reservoir, or both, if the Regional
Supervisor determines that an excessive
production rate could harm ultimate
recovery. An MPR or MER will be based
on well tests and any limitations
imposed by well and surface equipment,
sand production, reservoir sensitivity,
gas-oil and water-oil ratios, location of
perforated intervals, and prudent
operating practices.
(b) If the Regional Supervisor sets an
MPR for a producing well completion,
or an MER for a reservoir, you may not
exceed those rates except due to normal
variations and fluctuations in
production rates, as set by the Regional
Supervisor.
Flaring, Venting, and Burning
Hydrocarbons
§ 250.1160
When may I flare or vent gas?
(a) You must receive approval from
the Regional Supervisor to flare or vent
oil-well gas or gas-well gas at your
facility, except in the following
situations:
Condition
Additional requirements
(1) When the gas is lease use gas (produced natural gas which is used
on or for the benefit of lease operations such as gas used to operate
production facilities) or is used as an additive necessary to burn
waste products, such as H2S.
(2) During the restart of a facility that was shut in because of weather
conditions, such as a hurricane.
(3) During the blow down of transportation pipelines downstream of the
royalty meter.
The volume of gas flared or vented may not exceed the amount necessary for its intended purpose. Burning waste products may require
approval under other regulations.
(4) During the unloading or cleaning of a well, drill-stem testing, production testing, other well-evaluation testing, or the necessary blow
down to perform these procedures.
(5) When properly working equipment yields flash gas (natural gas released from liquid hydrocarbons as a result of a decrease in pressure, an increase in temperature, or both) from storage vessels or
other low-pressure production vessels, and you cannot economically
recover this flash gas.
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Flaring or venting may not exceed 48 cumulative hours without Regional Supervisor approval.
(i) You must report the location, time, flare/vent volume, and reason for
flaring/venting to the Regional Supervisor in writing within 72 hours
after the incident is over.
(ii) Additional approval may be required under subparts H and J of this
part.
You may not exceed 48 cumulative hours of flaring or venting per testing operation on a single completion without Regional Supervisor approval.
You may not flare or vent more than an average 50 MCF per day during any calendar month without Regional Supervisor approval.
Sfmt 4702
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Federal Register / Vol. 72, No. 43 / Tuesday, March 6, 2007 / Proposed Rules
Condition
Additional requirements
(6) When the equipment works properly but there is a temporary upset
condition, such as a hydrate or paraffin plug.
(i) For oil-well gas and gas-well flash gas (natural gas released from
condensate as a result of a decrease in pressure, an increase in
temperature, or both), you may not exceed 48 continuous hours of
flaring or venting without Regional Supervisor approval.
(ii) For primary gas-well gas (natural gas from a gas well completion
that is at or near its wellhead pressure; this does not include flash
gas), you may not exceed 2 continuous hours of flaring or venting
without Regional Supervisor approval.
(iii) You may not exceed 144 cumulative hours of flaring or venting during a calendar month without Regional Supervisor approval.
(i) For oil-well gas and gas-well flash gas, you may not exceed 48 continuous hours of flaring or venting without Regional Supervisor approval.
(ii) For primary gas-well gas, you may not exceed 2 continuous hours
of flaring or venting without Regional Supervisor approval.
(iii) You may not exceed 144 cumulative hours of flaring or venting during a calendar month without Regional Supervisor approval.
(iv) The continuous and cumulative hours allowed under this paragraph
may be counted separately from the hours under paragraph (a)(6) of
this section.
cprice-sewell on PROD1PC67 with PROPOSALS
(7) When equipment fails to work properly, including equipment maintenance and repair, or when you must relieve system pressures.
(b) You must inform the Regional
Supervisor and receive approval to flare
or vent gas before you exceed the
volume specified in your Development
and Production Plan submitted under
subpart B of this part, even if the flaring
or venting does not require approval
under paragraph (a) of this section. The
Regional Supervisor will determine
whether your proposed flaring or
venting complies with air emission
thresholds under subpart C of this part.
(c) The Regional Supervisor may
establish alternative approval
procedures to cover situations where
you cannot contact the MMS office,
such as during non-office hours.
(d) The Regional Supervisor may
specify a volume limit, or a shorter time
limit than specified elsewhere in this
part, in order to prevent air quality
degradation or loss of reserves.
(e) The Regional Supervisor will
evaluate your request for gas flaring or
venting and determine if the loss of
hydrocarbons is due to negligence, or
could be avoided.
(f) If you flare or vent gas without the
required approval, or if the Regional
Supervisor determines that you were
negligent or could have avoided flaring
or venting the gas, the hydrocarbons
will be considered avoidably lost or
wasted. You must pay royalties on the
loss or waste, according to part 202 of
this title. You must value any gas or
liquid hydrocarbons avoidably lost or
wasted under the provisions of part 206
of this title.
§ 250.1161 When may I flare or vent gas
for extended periods of time?
You may flare or vent oil-well gas and
gas-well flash gas for a period that the
Regional Supervisor will specify, and
which will not exceed 1 year, if the
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Regional Supervisor approves your
request for one of the following reasons:
(a) You initiate an action which, when
completed, will eliminate flaring and
venting;
(b) You submit to the Regional
Supervisor an evaluation supported by
engineering, geologic, and economic
data indicating that the oil and gas
produced from the well(s) will not
economically support the facilities
necessary to sell the gas; or to use the
gas on or for the benefit of, the lease; or
(c) The Regional Supervisor
determines that an improperly working
valve, pipe fitting, or similar component
results in flaring or venting of less than
10 MCF per day, and that it is prudent
to repair the leak at a later date. The
Regional Supervisor may exempt this
flaring or venting from the time limits
set in § 250.1160.
§ 250.1162 When may I burn produced
liquid hydrocarbons?
(a) You must request and receive
approval from the Regional Supervisor
to burn any produced liquid
hydrocarbons. The Regional Supervisor
may allow you to burn condensate if
you demonstrate that transporting it to
market or re-injecting it is not feasible
or poses a significant risk of harm to
offshore personnel or the environment.
In most cases, the Regional Supervisor
will not allow you to burn more than
300 barrels of condensate in total during
unloading or cleaning of a well, drillstem 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
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Regional Supervisor determines that
you were negligent or could have
avoided burning liquid hydrocarbons,
the hydrocarbons will be considered
avoidably lost or wasted. You must pay
royalties on the loss or waste, according
to part 202 of this title. You must value
any liquid hydrocarbons avoidably lost
or wasted under the provisions of part
206 of this title.
§ 250.1163 How must I measure gas flaring
or venting volumes and liquid hydrocarbon
burning volumes and what records must I
maintain?
(a) If your facility processes more than
an average of 2,000 BOPD during
[MONTH AND YEAR IN WHICH FINAL
RULE IS PUBLISHED], you must install
flare/vent meters within 120 days after
[THE MONTH AND YEAR IN WHICH
THE FINAL RULE IS PUBLISHED]. If
your facility processes more than an
average of 2,000 BOPD during a
calendar month after [MONTH AND
YEAR IN WHICH FINAL RULE IS
PUBLISHED], you must install flare/
vent meters within 90 days after the end
of the month in which the average
amount of oil processed exceeds 2,000
BOPD.
(1) The flare/vent meters must
measure all flared and vented gas within
2 percent accuracy.
(2) You must calibrate the meters
regularly, in accordance with the
manufacturer’s recommendation, or at
least once every 6 months, whichever is
shorter.
(b) You must report all hydrocarbons
produced from a well completion,
including all gas flared, gas vented, and
liquid hydrocarbons burned, to Minerals
Revenue Management on Form MMS–
4054 (Oil and Gas Operations Report),
in accordance with § 216.53 of this title.
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Federal Register / Vol. 72, No. 43 / Tuesday, March 6, 2007 / Proposed Rules
(1) You must report the amount of gas
flared and the amount of gas vented
separately.
(2) You may classify and report gas
used to operate equipment on the
facility (such as gas used to power
engines, gas used as pilot lights,
instrument gas, purge gas used to
prevent oxygen from entering the flare
or vent stack, sparge gas used to
regenerate glycol, and blanket gas used
to maintain pressure in low pressure
vessels) as lease use gas.
(3) You must report the amount of gas
flared and vented at each facility on a
lease or unit basis. Gas flared and
vented from multiple facilities on a
single lease or unit must be reported
separately.
(c) You must prepare and maintain
records detailing gas flaring, gas
venting, and liquid hydrocarbon
burning for each facility. You must
maintain these records for the period
specified in part 212 of this title. You
must keep these records on the facility
for 2 years and have them available for
inspection by MMS representatives.
After 2 years, you must maintain the
records, allow MMS representatives to
inspect the records upon request, and
provide copies to the Regional
Supervisor upon request, but you are
not required to keep them on the
facility. The records must include, at a
minimum:
(1) Daily volumes of gas flared, gas
vented, and liquid hydrocarbons
burned;
(2) Number of hours of gas flaring, gas
venting, and liquid hydrocarbon
burning, on a daily basis;
(3) A list of the wells contributing to
gas flaring, gas venting, and liquid
hydrocarbon burning, along with gas-oil
ratio data;
(4) Reasons for gas flaring, gas
venting, and liquid hydrocarbon
burning; and
(5) Documentation of all required
approvals.
(d) If your facility is required to have
flare/vent meters, you must maintain
the meter recordings for the period
specified in §§ 212.50 and 212.51 of this
title. You must keep these recordings on
the facility for 2 years and have them
available for inspection by MMS
representatives. After 2 years, you must
maintain the recordings, allow MMS
representatives to inspect the recordings
upon request, and provide copies to the
Regional Supervisor upon request, but
are not required to keep them on the
facility. These recordings must include
the begin times, end times, and volumes
for all flaring and venting incidents.
(e) If your flaring or venting of gas, or
burning of liquid hydrocarbons,
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18:26 Mar 05, 2007
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required written or oral approval, you
must submit documentation to the
Regional Supervisor summarizing the
location, dates, number of hours, and
volumes of gas flared, gas vented, and
liquid hydrocarbons burned under the
approval, as required under § 250.140.
§ 250.1164 What are the requirements for
flaring or venting gas containing H2S?
(a) You may not vent gas containing
H2S, except for minor releases during
maintenance and repair activities that
do not result in a 15-minute timeweighted average atmosphere
concentration of H2S of 20 ppm or
higher anywhere on the platform.
(b) You may flare gas containing H2S
only if you meet the requirements of
§§ 250.1160, 250.1161, 250.1163, and
the following additional requirements:
(1) You may not emit more than 15 lbs
of SO2 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 H2S. The
Regional Supervisor will use
information provided in the lessee’s H2S
Contingency Plan (§ 250.490(f)),
Exploration Plan, Development and
Production Plan, Development
Operations Coordination Document, and
associated documents to determine the
need for restrictions; and
(3) If the Regional Supervisor
determines that flaring at a facility or
group of facilities may significantly
affect the air quality of an onshore area,
the Regional Supervisor may require
you to conduct an air quality modeling
analysis to determine the potential
effect of facility emissions. The Regional
Supervisor may require monitoring and
reporting, or may restrict or prohibit
flaring, under §§ 250.303 and 250.304.
(c) You must report flared and vented
gas containing H2S as required under
§ 250.1163. In addition, the Regional
Supervisor may require you to submit
monthly reports of flared and vented gas
containing H2S. Each report must
contain, on a daily basis:
(1) The volume and duration of each
flaring and venting occurrence;
(2) H2S concentration in the flared or
vented gas; and
(3) The calculated amount of SO2
emitted.
Enhanced Recovery
§ 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
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9899
ultimate recovery of oil or gas under
sound engineering and economic
principles.
(b) Before initiating enhanced
recovery operations, you must submit a
proposed plan to the Regional
Supervisor and receive approval for
pressure maintenance, secondary or
tertiary recovery, cycling, and similar
recovery operations intended to increase
the ultimate recovery of oil and gas from
a reservoir. The proposed plan must
include, for each project reservoir, a
brief geologic and engineering overview,
structure map, well log section, Form
MMS–127, and any additional
information required by the Regional
Supervisor.
(c) You must report to Minerals
Revenue Management the volumes of
oil, gas, or other substances injected,
produced, or produced for a second
time under § 216.53 of this title.
Special Alaska OCS Region
Requirements
§ 250.1166 What additional reporting is
required for developments in the Alaska
OCS Region?
(a) For any development in the Alaska
OCS Region, you must submit an annual
reservoir management report to the
Regional Supervisor. The report must
contain information detailing the
activities performed during the previous
year and planned for the upcoming year
that will provide for:
(1) The prevention of waste;
(2) The protection of correlative
rights; and
(3) A greater ultimate recovery of oil
and gas.
(b) If your development is jointly
regulated by MMS and the State of
Alaska, MMS and the AOGCC will
jointly determine appropriate reporting
requirements to minimize or eliminate
duplicate reporting requirements.
(c) Every time you are required to
submit Form MMS–127 under
§ 250.1155, you must request an MER
for each producing sensitive reservoir in
the Alaska OCS Region, unless
otherwise instructed by the Regional
Supervisor.
Information Needed With Forms and
for Approvals
§ 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:
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cprice-sewell on PROD1PC67 with PROPOSALS
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Federal Register / Vol. 72, No. 43 / Tuesday, March 6, 2007 / Proposed Rules
(a) Maps:
(1) Base map with surface,
bottomhole, and completion locations with respect to the unit or
lease line and the orientation of
representative seismic lines or
cross sections ...............................
(2) Structure maps with penetration
point and subsea depth for each
well penetrating the reservoirs,
highlighting subject wells; reservoir boundaries; and original
and current fluid levels ..................
(3) Net sand isopach with total net
sand penetrated for each well,
identified at the penetration point
(4) Net hydrocarbon isopach with
net feet of pay for each well, identified at the penetration point ........
(b) Seismic data:
(1) Representative seismic lines, including strike and dip lines that
confirm the structure; indicate polarity ...............................................
(2) Time/depth correlation table for
seismic data ..................................
(3) Amplitude extraction of seismic
horizon, if applicable .....................
(c) Logs:
(1) Well log sections with tops and
bottoms of the reservoir(s) and
proposed or existing perforations
(2) Structural cross-sections showing
the subject well and nearby wells
(d) Engineering Data:
(1) Estimated recoverable reserves
for each well completion in the
reservoir; total recoverable reserves for each reservoir; method
of calculation; reservoir parameters used in volumetric and decline curve analysis .......................
(2) Well schematics showing current
and proposed conditions ...............
(3) The drive mechanism of each
reservoir ........................................
(4) Pressure data, by date, and
whether they are estimated or
measured ......................................
(5) Production data and decline
curve analysis indicative of the
reservoir performance ...................
(6) Reservoir simulation with the reservoir parameters used, history
matches, and prediction runs (include proposed development scenario) .............................................
(e) General information:
(1) Detailed economic analysis ........
(2) Reservoir name and whether or
not it is competitive as defined
under § 250.105 ............................
(3) Operator name, lessee name(s),
block, lease number, royalty rate,
and unit number (if applicable) of
all relevant leases .........................
(4) Brief geologic overview of project
(5) Explanation of why the proposed
completion scenario will not harm
ultimate recovery ...........................
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WPT MMS–
126
SRI MMS–127
Gas cap
production
Downhole
commingling
Reservoir
reclassification
Production
within 500-ft of
a Unit or
Lease Line
........................
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✓
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9901
Federal Register / Vol. 72, No. 43 / Tuesday, March 6, 2007 / Proposed Rules
(6) List of all wells in subject reservoirs that have ever produced or
been used for injection ..................
WPT MMS–
126
SRI MMS–127
Gas cap
production
Downhole
commingling
Reservoir
reclassification
Production
within 500-ft of
a Unit or
Lease Line
........................
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✓
✓
✓
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† 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.
the Waterways Safety Branch of Sector
San Francisco between 9 a.m. and 4
p.m., Monday through Friday, except
Federal holidays.
FOR FURTHER INFORMATION CONTACT:
Lieutenant Eric Ramos, U.S. Coast
Guard Sector San Francisco, at (415)
556–2950 or Sector San Francisco 24hour Command Center at (415) 399–
3547.
SUPPLEMENTARY INFORMATION:
(f) Depending on the above
requirement, you must submit
appropriate payment of the service
fee(s) listed in § 250.125.
[FR Doc. E7–3846 Filed 3–5–07; 8:45 am]
BILLING CODE 4310–MR–P
DEPARTMENT OF HOMELAND
SECURITY
Coast Guard
33 CFR Part 165
[COTP San Francisco Bay 07–003]
RIN 1625–AA00
Safety Zone; Liberty Island Conductor
Removal, Sacramento River, CA
Coast Guard, DHS.
Notice of proposed rulemaking.
AGENCY:
cprice-sewell on PROD1PC67 with PROPOSALS
ACTION:
SUMMARY: The Coast Guard proposes to
establish a safety zone in the navigable
waters of the Sacramento River that will
prohibit vessels and people from
entering into or remaining within close
proximity to the deep water channel.
Pacific Gas and Electric Company
(PG&E) will be removing a conductor
from the Liberty Island towers, two of
which cross over the deep water
channel, on March 28, 2007. The
proposed safety zone will close the deep
water channel for approximately 30
minutes during the conductor removal.
DATES: Comments and related material
must reach the Coast Guard on or before
March 14, 2007.
ADDRESSES: You may mail comments
and related material to United States
Coast Guard Sector San Francisco,
Waterways Safety Branch, Yerba Buena
Island, Bldg. 278, San Francisco,
California, 94130. The Waterways Safety
Branch of Sector San Francisco
maintains the public docket for this
rulemaking. Comments and material
received from the public, as well as
documents indicated in this preamble as
being available in the docket, will
become part of this docket and will be
available for inspection or copying at
VerDate Aug<31>2005
15:32 Mar 05, 2007
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Request for Comments
We encourage you to participate in
this rulemaking by submitting
comments and related material. If you
do so, please include your name and
address, identify the docket number for
this rulemaking (COTP SF 07–003),
indicate the specific section of this
document to which each comment
applies, and give the reason for each
comment. Please submit all comments
and related material in an unbound
format, no larger than 81⁄2 by 11 inches,
suitable for copying. If you would like
to know they reached us, please enclose
a stamped, self-addressed postcard or
envelope. We will consider all
comments and material received during
the comment period. We may change
this proposed rule in view of them.
Public Meeting
We do not now plan to hold a public
meeting. But you may submit a request
for a meeting by writing to Coast Guard
Sector San Francisco, Waterways Safety
Branch at the address under ADDRESSES
explaining why one would be
beneficial. If we determine that one
would aid this rulemaking, we will hold
one at a time and place announced by
a later notice in the Federal Register.
Background and Purpose
PG&E will be removing a conductor
from the Liberty Island towers on March
28, 2007. Two of the towers cross the
Sacramento deep water channel. PG&E
will use a helicopter to cut the
conductor off of one tower and it will
fall into the water. They will then
recover the cut conductor and place it
on the bank before continuing to remove
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the rest of the conductors from the
remaining towers that are over land.
Discussion of Proposed Rule
This proposed safety zone will
encompass the navigable waters of the
Sacramento River from the surface to
the sea floor, encompassing a circular
area with a 500-yard radius at position
38°17.072′N / 121°39.619′W (NAD 83)
for the removal of a conductor from a
tower that crosses over the deep water
channel. This proposed safety zone is
necessary to protect persons and vessels
from hazards, injury, and damage
associated with the conductor removal.
Regulatory Evaluation
This proposed rule is not a
‘‘significant regulatory action’’ under
section 3(f) of Executive Order 12866,
Regulatory Planning and Review, and
does not require an assessment of
potential costs and benefits under
section 6(a)(3) of that Order. The Office
of Management and Budget has not
reviewed it under that Order.
We expect the economic impact of
this proposed rule to be so minimal that
a full Regulatory Evaluation is
unnecessary.
Although this rule will restrict access
to the waters encompassed by the
proposed safety zone, the effect of this
rule is not expected to be significant
because the local waterway users will be
notified via public broadcast notice to
mariners to ensure the proposed safety
zone will result in minimum impact.
The entities most likely to be affected
are pleasure craft engaged in
recreational activities.
Small Entities
Under the Regulatory Flexibility Act
(5 U.S.C. 601–612), we have considered
whether this proposed rule would have
a significant economic impact on a
substantial number of small entities.
The term ‘‘small entities’’ comprises
small businesses, not-for-profit
organizations that are independently
owned and operated and are not
dominant in their fields, and
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| File Type | application/pdf |
| File Title | Document |
| Subject | Extracted Pages |
| Author | U.S. Government Printing Office |
| File Modified | 2007-03-06 |
| File Created | 2007-03-06 |