9884 Federal Register / Vol. 72, No. 43 / Tuesday, March 6, 2007 / Proposed Rules 

TABLE 1.—AIRBUS SERVICE BULLETINS—Continued 

Service Bulletin Revision level Date 

A320–27–1117 .................................................................................................................................... Revision 03 .............. August 24, 2001. 

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 

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 

(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. 

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. 

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 

Minerals Management Service 

30 CFR Part 250 

RIN 1010–AD12 

Oil and Gas and Sulphur Operations 

on the Outer Continental Shelf (OCS)—

Oil and Gas Production Requirements 

AGENCY: Minerals Management Service 

(MMS), Interior. 

ACTION: Proposed rule. 

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. 


cprice-sewell on PROD1PC67 with PROPOSALS
Federal Register / Vol. 72, No. 43 / Tuesday, March 6, 2007 / Proposed Rules 9885 

• 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 

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: 

Current rule Proposed rule 

§ 250.1100 Definitions for production rates ........................................... § 250.105 Definitions. 

§ 250.105 Definitions. 

§ 250.1101 General requirements and classification of reservoirs ........ § 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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9886 Federal Register / Vol. 72, No. 43 / Tuesday, March 6, 2007 / Proposed Rules 

Current rule Proposed rule 

§ 250.1156 What steps must I take to receive approval to produce 

within 500 feet of a unit or lease line? 

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

§ 250.1102 Oil and gas production rates ............................................... Requirements for production rates are largely eliminated. Portions retained were combined with new information in ‘‘§ 250.1159 May the 

Regional Supervisor limit my well or reservoir production rates?’’

§ 250.1103 Well production testing ........................................................ § 250.1151 How often must I conduct well production tests? 

§ 250.1152 How do I conduct well tests? 

§ 250.1104 Bottomhole pressure survey ............................................... § 250.1153 When must I conduct a static bottomhole pressure survey? 

§ 250.1105 Flaring or venting of gas and burning liquid hydrocarbons § 250.1160 When may I flare or vent gas? 

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

time? 

§ 250.1162 When may I burn produced liquid hydrocarbons? 

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

§ 250.1164 What are the requirements for flaring or venting gas containing H2S? 

§ 250.1106 Downhole commingling ....................................................... § 250.1158 How do I receive approval to downhole commingle hydrocarbons? 

§ 250.1107 Enhanced oil and gas recovery operations ........................ § 250.1165 What must I do for enhanced recovery operations? 

New ........................................................................................................... § 250.1159 May the Regional Supervisor limit my well or reservoir 

production rates? 

§ 250.1166 What additional reporting is required for developments in 

the Alaska Region? 

§ 250.1167 What information must I submit for approvals? 

The organization of the proposed rule 

reflects the actual sequence of events 

that occurs as wells are developed and 

the resources produced. The proposed 

rule is written in plain language to 

conform to the DOI’s standards for rule 

writing. These changes include 

incorporating tables, using a question 

format for section headings, and using 

pronouns. These changes would make 

the rule easier to understand. Finally, a 

table at the end of the rule lists the 

information that operators would have 

to submit to MMS to receive approvals 

for various operations. 

Major Changes to the Rule 

Some requirements from the previous 

edition of subpart K would be 

eliminated by the proposed rule because 

they are unnecessary in today’s 

petroleum industry. For example, MMS 

required operators to establish 

maximum production rates (MPR’s) for 

producing well completions, and 

maximum efficient rates (MER’s) for 

producing reservoirs, in OCS Order No. 

11 in 1974, during a period of oil 

shortages and energy crises. In 1988, 

MMS reduced the MER requirement. 

Currently, MER’s are required only on 

sensitive reservoirs (primarily oil 

reservoirs with associated gas caps). 

Determining and maintaining 

production rates imposes a significant 

burden on operators. Based on the past 

30 years of experience, MMS has 

concluded that maximum rate 

requirements and production balancing 

requirements can be largely eliminated 

without significant detriment to efforts 

for conservation and maximization of 

ultimate recovery. However, the 

proposed rule would allow the Regional 

Supervisor to set production rates in 

cases where excessive production could 

harm ultimate recovery from the 

reservoir. 

The proposed rule would clarify 

required information submittals to 

MMS, including requirements relating 

to the documents submitted to MMS 

and the timing of those submissions. For 

example, there is additional guidance 

on notifying adjoining operators 

regarding production within 500 feet of 

a common lease or unit line. The 

proposed rule would provide more 

detail as to when the notification must 

occur, what the notice must include, 

and how to verify the notification with 

MMS. 

The proposed rule would incorporate 

several Notices to Lessees and Operators 

(NTLs) that clarify the current 

regulations. These NTLs would be 

obsolete if the proposed rule becomes 

final and MMS would withdraw all of 

these NTLs at that time. However, if 

necessary, MMS would issue additional 

NTLs to provide guidance. The NTLs 

affected include: 

• NTL No. 97–16, ‘‘Production 

Within 500 Feet of a Unit or Lease 

Line,’’ effective August 1, 1997. This 

NTL clarifies MMS policy on issuing 

approvals for production within 500 feet 

of a unit or lease line, and includes 

details on what the requesting operator 

needs to provide to MMS for approval. 

Those details are addressed in the 

proposed rule. 

• NTL No. 98–23, ‘‘Interim Reporting 

Requirements for 30 CFR 250, subpart 

K, Oil and Gas Production Rates,’’

effective October 15, 1998. This NTL 

addressed oral approvals for gas flaring 

and relaxed some of the requirements 

regarding production rates, including 

MER and MPR in certain circumstances. 

The NTL clarified the submittal of 

written summary letters on flaring 

incidents that received oral approval. 

These requirements are addressed in the 

proposed rule. 

• NTL No. 99–G20, ‘‘Downhole 

Commingling Applications,’’ effective 

September 7, 1999. This NTL was 

issued in conjunction with NTL No. 99–

G19. It clarifies what information the 

applicant needs to include in downhole 

commingling applications to ensure that 

the application is processed without 

delay. These information requirements 

were added to the proposed rule. 

• NTL No. 2006–N06, ‘‘Flaring and 

Venting Approvals,’’ effective December 

19, 2006. This NTL clarifies the 

definitions of flaring and venting, the 

record-keeping requirements, the 

classification of emitted natural gas, and 

the MMS policy regarding continuous 

flaring or venting of small volumes of 

oil-well gas or gas-well gas from storage 

vessels or other low-pressure 

production vessels when the gas cannot 

be economically recovered. These issues 

are addressed in the proposed rule. This 

NTL also provides contact information 

for each Region and provides sample 


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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 

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. 

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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9888 Federal Register / Vol. 72, No. 43 / Tuesday, March 6, 2007 / Proposed Rules 

downhole commingle hydrocarbons and 

the service fee that must accompany 

your request. For downhole 

commingling in a competitive reservoir, 

the operator would be required to notify 

the operators of all leases that contain 

the reservoir. The request for approval 

must document this notification. 

Operators of the other leases would 

have 30 days after the notification to 

provide the Regional Supervisor with 

letters of acceptance or objection. If the 

notified operators do not respond 

within the specified period, the 

Regional Supervisor will assume the 

operators do not object. The Regional 

Supervisor will consider any objections, 

but may approve the commingling 

request to protect correlative rights. This 

section would also incorporate issues 

addressed in NTL’s No. 99–G19 and 99–

G20. 

Production Rates 

§ 250.1159 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 

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 

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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Federal Register / Vol. 72, No. 43 / Tuesday, March 6, 2007 / Proposed Rules 9889 

pursue civil penalties, under 30 CFR 

250 subpart N—Outer Continental Shelf 

(OCS) Civil Penalties, if we determine 

that the loss was avoidable or due to 

negligence. 

§ 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. 

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. 

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 

management plans enable the MMS to 

monitor recoverable oil and assure 

proper allocation of reserves for royalty 

payment and to be consistent with the 

State of Alaska requirements. 

This provision would also enable the 

MMS to manage its responsibility for 

conservation of resources on a real time 

basis. The number, type, spacing and 

sequencing of development wells 

(producers and injectors) will vary from 

the original approved development and 

production plan as more information on 

the reservoir is obtained. An annual 

reservoir management plan would 

enable the MMS to track development 

activities with the approved 

development and production plan and 

assure maximum recovery based on the 

most current knowledge of the reservoir. 

Information Needed With Forms and for 

Approvals 

§ 250.1167 What information must I 

submit with forms and for approvals? 

This proposed table is designed to be an 

easy-to-use reference to determine the 

information and supporting 

documentation to submit to the 

Regional Supervisor and to remind 

lessees to pay the appropriate service 

fee. Forms MMS–126 (Well Potential 

Test Report) and MMS–127 (Sensitive 

Reservoir Information Report) would 

require supporting documents. Also, 

several operations covered under 

subpart K (gas cap production, 

downhole commingling, reservoir 

reclassification, and production within 

500 feet of a unit or lease line), would 

require that the operator submit 

applications and supporting documents 

to the Regional Supervisor. All of these 

documents are covered in the table. 

Questions 

In addition to comments on these 

proposed regulations, MMS is 

requesting comments on the following 

questions. 

1. Are these regulations well 

organized and easy to read? 

2. Is the submittal table useful? 

3. Is the 2,000 BOPD requirement for 

installing flare/vent meters reasonable? 

Are the cost estimates accurate? 

4. Would the requirement to install 

flare/vent meters pose a safety hazard by 

restricting flow during emergency 

facility blowdowns, or are accurate 

meters (such as ultrasonic meters) 

available that do not impede gas flow? 

5. Should MMS require operators to 

flare natural gas instead of venting it, 

under approved flaring and venting 

conditions? This question is based on a 

recommendation from the GAO report 

on flaring and venting natural gas, and 

reflects concerns about the amount of 

greenhouse gas that is released into the 

environment by venting. MMS is 

studying this recommendation before 

proposing any regulatory change. We 

would like comments on this issue, 

including comments related to 

additional costs, environmental 

impacts, and conditions or situations 

where flaring may not be advisable. 

Procedural Matters 

Public Availability of Comments 

Before including your address, phone 

number, e-mail address, or other 

personal identifying information in your 

comment, you should be aware that 

your entire comment—including your 

personal identifying information—may 

be made publicly available at any time. 

While you can ask us in your comment 

to withhold your personal identifying 

information from public review, we 

cannot guarantee that we will be able to 

do so. 

Regulatory Planning and Review 

(Executive Order (E.O.) 12866) 

This proposed rule is not a significant 

rule as determined by the Office of 

Management and Budget (OMB) and is 

not subject to review under E.O. 12866. 

(1) The proposed rule would not have 

an annual economic effect of $100 

million or more on the economy. It 

would not adversely affect in a material 

way the economy, productivity, 

competition, jobs, the environment, 

public health or safety, or State, local, 

or tribal governments or communities. A 

cost-benefit and economic analysis is 

not required. 

This proposed rule revises the 

requirements for oil and gas production. 

The changes in the rule are not 

significant enough to have an impact on 

the economy or an economic sector, 

productivity, jobs, the environment, or 

other units of government. Some of the 

current requirements would be relaxed. 

For example, limits on production rates 

were eliminated in most cases. This 

would allow the operators to produce 

the oil and gas at the rates that they 

determine are best, and would not have 

a significant effect on any sector of the 

economy. 

(2) The proposed rule would not 

create a serious inconsistency or 

otherwise interfere with action taken or 

planned by another agency because 

MMS is the only Federal government 

agency directly involved in setting 

production requirements for the 

offshore oil and natural gas industry. 

(3) This proposed rule would not alter 

the budgetary effects of entitlements, 

grants, user fees or loan programs, or the 

rights and obligations of their recipients. 


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9890 Federal Register / Vol. 72, No. 43 / Tuesday, March 6, 2007 / Proposed Rules 

(4) This proposed rule would not raise 

novel legal or policy issues. There are 

some changes in production 

requirements in this proposal, but most 

of the changes clarify existing MMS 

requirements. Some may require 

additional paperwork for the operators. 

Since the basic production requirements 

are not changed, and restrictions on 

production rates are decreased, this 

proposed rule should not raise novel 

legal or policy issues. 

Regulatory Flexibility Act (RFA) 

The Department of the Interior 

certifies that this proposed rule would 

not have a significant economic effect 

on a substantial number of small entities 

as defined under the RFA (5 U.S.C. 601 

et seq.). An initial Regulatory Flexibility 

Analysis is not required. Accordingly, a 

Small Entity Compliance Guide is not 

required. 

This rule applies to all lessees 

operating on the OCS. Lessees fall under 

the Small Business Administration’s 

North American Industry Classification 

System (NAICS) code 211111, Crude 

Petroleum and Natural Gas Extraction. 

Under this NAICS code, companies with 

less than 500 employees are considered 

small businesses. MMS estimates that 

130 lessees explore for and produce oil 

and gas on the OCS; approximately 70 

percent of them (91 companies) fall into 

the small business category. The 

proposed regulation would therefore 

affect a substantial number of small 

entities. However, we have determined 

that it would not have a significant 

economic effect on these small entities. 

One new requirement that would 

impose a cost to operators is a 

requirement to install flaring/venting 

meters on all facilities that process more 

than 2,000 BOPD. The GAO report on 

flaring and venting natural gas, released 

in July 2004, recommended that MMS 

require these meters to improve 

oversight. MMS agrees with this 

recommendation. MMS regulations 

allow flaring and venting in very limited 

circumstances. These meters would 

help MMS: 

• Verify the amounts of natural gas 

that operators flare or vent into the 

environment; 

• Prevent waste of resources; 

• Collect the proper royalties on 

avoidably flared or vented gas; 

• Determine if an operator is violating 

MMS regulations; and 

• Assess the impacts on the 

environment. 

In determining the criteria for which 

facilities must install the meters, MMS 

considered the cost of the meters and 

the amount of production needed to 

justify the cost. To ensure that the 

requirement to install flare/vent meters 

would not produce an undue burden on 

small companies, it was limited to those 

facilities that process more than an 

average of 2,000 BOPD. 

MMS estimates that 34 companies 

would have to install meters on 112 

facilities at an average cost of $77,000 

per facility and a total cost to industry 

of $8,624,000 (112 × $77,000 = 

$8,624,000). Of those, nine companies 

are considered small businesses, based 

on the NAICS. These nine companies 

represent only 7 percent of the 130 

operators on the OCS. We estimate that 

seven of these nine companies would 

need to install meters on one facility 

each; one company would need to 

install meters on two facilities; and one 

company would need to install meters 

on three facilities. This represents an 

average cost of $105,875 for each of the 

small companies (11 facilities × 

$77,000/9 companies). The average cost 

to non small companies would be 

$311,080 per company (101 facilities × 

$77,000/25 companies). In addition, this 

does not represent an unfair burden to 

small companies because the cost of 

these meters is small in comparison to 

the revenues generated by the amount of 

oil processed by those facilities. 

Your comments are important. The 

Small Business and Agriculture 

Regulatory Enforcement Ombudsman 

and 10 Regional Fairness Boards were 

established to receive comments from 

small businesses about Federal agency 

enforcement actions. The Ombudsman 

will annually evaluate the enforcement 

activities and rate each agency’s 

responsiveness to small business. If you 

wish to comment on the actions of 

MMS, call 1–888–734–3247. You may 

comment to the Small Business 

Administration without fear of 

retaliation. Disciplinary action for 

retaliation by an MMS employee may 

include suspension or termination from 

employment with the DOI. 

Small Business Regulatory Enforcement 

Fairness Act (SBREFA) 

The proposed rule is not a major rule 

under SBREFA (5 U.S.C. 804(2)). This 

proposed rule: 

a. Would not have an annual effect on 

the economy of $100 million or more. 

This proposed rule revises the 

requirements for oil and gas production. 

The changes would not have an impact 

on the economy or an economic sector, 

productivity, jobs, the environment, or 

other units of government. Most of the 

new requirements are paperwork 

requirements, and would not add 

significant time to development and 

production processes. One new 

requirement would add new costs for 

some operators. Operators would be 

required to install flare/vent meters on 

any facility that processes more than an 

average of 2,000 BOPD. MMS estimates 

that 34 companies would have to install 

meters on 112 facilities at an average 

cost of $77,000 per facility and a total 

cost to industry of $8,624,000 (112 × 

$77,000 = $8,624,000). 

b. Would not cause a major increase 

in costs or prices for consumers, 

individual industries, Federal, State, or 

local government agencies, or 

geographic regions. 

In most cases, this proposed rule 

would eliminate the requirement for 

operators to set limits on production 

rates, allowing the operators to 

determine the best rate to produce their 

reservoirs. The limits on burning, 

flaring, and venting are clearer. These 

limits would encourage conservation of 

our natural resources, without putting 

undue production restrictions on 

operators. There would be a new 

requirement to install meters on 

facilities that process more than an 

average of 2,000 BOPD. As discussed 

above, this requirement would not 

significantly increase the cost of doing 

business offshore. 

c. Would not have significant adverse 

effects on competition, employment, 

investment, productivity, innovation, or 

the ability of U.S.-based enterprises to 

compete with foreign-based enterprises. 

This proposed rule would eliminate the 

requirement for operators to set limits 

on production rates, allowing the 

operators to determine the best rate to 

produce their reservoirs. There are 

clearer limits on burning, flaring, and 

venting, which would encourage 

conservation of our natural resources. 

Unfunded Mandates Reform Act 

(UMRA) of 1995 

This proposed rule would not impose 

an unfunded mandate on State, local, or 

tribal governments or the private sector 

of more than $100 million per year. The 

proposed rule would not have a 

significant or unique effect on State, 

local, or tribal governments or the 

private sector. A statement containing 

the information required by UMRA (2 

U.S.C. 1531 et seq.) is not required. This 

is because the proposal would not affect 

State, local, or tribal governments, and 

the effect on the private sector is small. 

Takings Implication Assessment 

(Executive Order 12630) 

The proposed rule is not a 

governmental action capable of 

interference with constitutionally 

protected property rights. Thus, MMS 

did not need to prepare a Takings 

Implication Assessment according to 


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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. 

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’’

in your comments. You may obtain a 

copy of the supporting statement for the 

new collection of information by 

contacting the Bureau’s Information 

Collection Clearance Officer at (202) 

208–7744. 

The PRA provides that an agency may 

not conduct or sponsor, and a person is 

not required to respond to, a collection 

of information unless it displays a 

currently valid OMB control number. 

OMB is required to make a decision 

concerning the collection of information 

contained in these proposed regulations 

30–60 days after publication of this 

document in the Federal Register. 

Therefore, a comment to OMB is best 

assured of having its full effect if OMB 

receives it by April 5, 2007. This does 

not affect the deadline for the public to 

comment to MMS on the proposed 

regulations. 

The title of the collection of 

information for the rule is ‘‘30 CFR 250, 

Subpart K, Oil and Gas Production 

Requirements.’’ The proposed 

regulations concern oil and gas 

production requirements, and the 

information is used in our efforts to 

conserve natural resources, prevent 

waste, and protect correlative rights, 

including the government’s royalty 

interest. 

Respondents are the approximately 

130 Federal oil and gas and sulphur 

lessees. Responses to this collection are 

mandatory. The frequency of response is 

on occasion, monthly, semi-annually, 

annually, and as a result of situations 

encountered depending upon the 

requirement. The information collection 

(IC) does not include questions of a 

sensitive nature. MMS will protect 

proprietary information according to the 

Freedom of Information Act (5 U.S.C. 

552) and its implementing regulations 

(43 CFR part 2), and 30 CFR 250.196, 

‘‘Data and information to be made 

available to the public,’’ and 30 CFR 

part 252, ‘‘OCS Oil and Gas Information 

Program.’’ Proprietary information 

concerning geological and geophysical 

data will be protected according to 43 

U.S.C. 1352. 

The collection of information required 

by the current subpart K regulations is 

approved under OMB Control Number 

1010–0041. The proposed rule imposes 

minor changes to the information 

collection burden. The changes are: 

• Report to Minerals Revenue 

Management (MRM) measured gas 

flaring or venting and liquid 

hydrocarbon burning. Submit periodic 

reports of volumes of oil, gas, or other 

substances injected, produced, or 

produced for a second time. Both 

requirements and burdens are now 

reported to MRM and their respective 

burdens are covered under OMB Control 

Number 1010–0139 (–154 burden 

hours); 

• Request Regional Supervisor 

approval for emitting more than 15 lbs. 

of 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. 

30 CFR 250 Subpart K Reporting & recordkeeping requirement 

Fee/non-hour cost 

Hour burden Average number of 

annual responses 

Annual burden 

hours 

1151(a), (c); 1155; 1165; 

1166(c); 1167.

Submit form MMS–126 and supporting information .. 3 1,325 forms ...................... 3,975 

Submit form MMS–127 and supporting information .. 2.2 2,189 forms ...................... 4,816 


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9892 Federal Register / Vol. 72, No. 43 / Tuesday, March 6, 2007 / Proposed Rules 

30 CFR 250 Subpart K Reporting & recordkeeping requirement 

Fee/non-hour cost 

Hour burden Average number of 

annual responses 

Annual burden 

hours 

Submit form MMS–128 and supporting information .. 0.1—3 13,000 GOM forms ..........

600 POCS forms 

1,336* 

1151(b) .............................. Request extension of time to submit results of semiannual well test.0.5 37 requests ...................... 19 

1152(b), (c) ....................... Obtain Regional Supervisor approval to conduct well 

testing using alternative procedures; conduct 

tests/retests to establish proper MPR or MER; 

conduct multipoint backpressure test for open flow 

potential.

0.5 37 requests ...................... 19 

1152(d) .............................. Provide advance notice of time and date of well 

tests.

0.5 10 notices ........................ 5 

1153 .................................. Submit results of all static bottomhole pressure surveys obtained by lessee using form MMS–140. 

Request departure requirement w/justification to 

Regional Supervisor; submit with Form MMS–140 

and supporting information.

14 

1 

1,270 surveys ..................

120 survey waivers ..........

17,780 

120 

1154; 1167 ........................ Request reclassification of reservoir for Regional 

Supervisor approval and submit supporting information.

6 20 requests ...................... 120 

1156; 1167 ........................ Request approval to produce within 500 feet of a 

unit or lease line and submit supporting information; notify operators; provide proof of date to Regional Supervisor.

5 50 requests ...................... 250 

3,300 × 50 requests = $165,000 

1157; 1167 ........................ Request approval to produce gas cap of a sensitive 

reservoir and submit supporting information; obtain approval to produce gas from an oil reservoir 

with an associated gas cap.

12 125 requests .................... 1,500 

$4,200 × 125 requests = $525,000 

1158; 1167 ........................ Submit request to downhole commingle hydrocarbons and supporting information; notify operators; provide proof of date to Regional Supervisor.6 119 applications ............... 714 

$4,900 × 119 applications = $583,100 

1160; 1161 ........................ Request Regional Supervisor approval/inform to 

flare or vent oil-well gas or gas-well gas/exceed 

volume; submit documentation.

0.5 1,007 requests ................. 504 

1162; 1163(e) .................... Request approval to burn produced liquid hydrocarbons; submit documentation.0.5 60 requests ...................... 30 

NEW 1163 ......................... Initial purchase and install gas meters to measure 

the amount of gas flared or vented. This is a nonhour cost burden.

0 112 ................................... 0 

112 meters @ $77,000 ea = $8,624,000 

NEW 1163(b); 1165(c) ...... Report to MRM measured gas flaring or venting and liquid hydrocarbon burning—burden covered 

under 1010–0139 

0 

NEW 1164(b)(1) ................ Request Regional Supervisor approval for emitting 

more than 15 lbs. of SO2.

0.5 20 requests ...................... 10 

1164(b)(2) ......................... H2S Contingency, Exploration, or Development and Production Plans—burden covered under 

1010–0141 and 1010–0151 

0 

NEW 1164(b)(3) ................ Submit to Regional Supervisor air quality modeling 

analysis.

40 1 modeling analysis ......... 40 

1164(c) .............................. Submit monthly reports of flared or vented gas containing H2S.2 3 operators × 12 mos. = 

36.

72 

1165 .................................. Submit proposed plan for enhanced recovery operations.12 27 plans ........................... 324 

1165(c) .............................. Submit periodic reports of volumes of oil, gas, or other substances injected, produced, or produced for a second time—burden covered under OMB approval 1010–0139 0 


cprice-sewell on PROD1PC67 with PROPOSALS
Federal Register / Vol. 72, No. 43 / Tuesday, March 6, 2007 / Proposed Rules 9893 

30 CFR 250 Subpart K Reporting & recordkeeping requirement 

Fee/non-hour cost 

Hour burden Average number of 

annual responses 

Annual burden 

hours 

NEW 1166 ......................... Alaska Region only: submit to Regional Supervisor 

annual reservoir management report and supporting information.

1 

100 

1 (required by State, 

MMS gets copy).

1 new develop not State 

lands.

1 

100 

20 3 annual revisions ........... 60 

NEW 1150–1167 ............... General departure or alternative compliance requests not specifically covered elsewhere in subpart K.1 5 ....................................... 5 

Reporting Subtotal 20,175 .............................. 31,800 

1163(c), (d) ....................... Maintain records for 6 years detailing gas flaring or 

venting; maintain meter records and provide copies if requested.

13 869 platforms ................... 11,297 

1163(c) .............................. Maintain records for 6 years detailing liquid hydrocarbon burning; maintain meter records and provide copies if requested.0.5 60 occurrences ................ 30 

Recordkeeping Subtotal 929 ................................... 11,327 

Total Burden 21,104 .............................. 43,127 

$9,897,100 

* 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 

the methods you use to estimate major 

cost factors, including system and 

technology acquisition, expected useful 

life of capital equipment, discount 

rate(s), and the period over which you 

incur costs. Capital and start-up costs 

include, among other items, computers 

and software you purchase to prepare 

for collecting information; monitoring, 

sampling, drilling, and testing 

equipment; and record storage facilities. 

Generally, our estimates should not 

include equipment or services 

purchased: before October 1, 1995; to 

comply with requirements not 

associated with the information 

collection; for reasons other than to 

provide information or keep records for 

the Government; or as part of customary 

and usual business or private practices. 

National Environmental Policy Act 

(NEPA) of 1969 

We analyzed this proposed rule in 

accordance with the criteria of the 

NEPA and 516 Departmental Manual 6, 

Appendix 10.4C, ‘‘issuance, and/or 

modification of regulations.’’ MMS 

completed a Categorical Exclusion 

Review (CER) for this action on May 31, 

2005, and concluded: ‘‘The proposed 

rulemaking does not represent an 

exception to the established criteria for 

categorical exclusion. Therefore, 

preparation of an environmental 

document will not be required, and 

further documentation of this CER is not 

required.’’

Energy Supply, Distribution, or Use 

(Executive Order 13211) 

Executive Order 13211 requires the 

agency to prepare a Statement of Energy 

Effects when it takes a regulatory action 

that is identified as a significant energy 

action. This proposed rule is not a 

significant energy action, and therefore 

would not require a Statement of Energy 

Effects because it: 

a. Is not a significant regulatory action 

under E.O. 12866, 

b. Is not likely to have a significant 

adverse effect on the supply, 

distribution, or use of energy, and 

c. Has not been designated by the 

Administrator of the Office of 

Information and Regulatory Affairs, 

OMB, as a significant energy action. 

Consultation With Indian Tribes 

(Executive Order 13175) 

Under the criteria in E.O. 13175, we 

have evaluated this proposed rule and 

determined that it has no potential 

effects on federally recognized Indian 

tribes. There are no Indian or tribal 

lands on the OCS. 

Clarity of This Regulation (Executive 

Order 12866) 

Executive Order 12866 requires each 

agency to write regulations that are easy 

to understand. MMS invites your 

comments on how to make this 

proposed rule easier to understand, 

including answers to questions such as 

the following: 


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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. 

List of Subjects in 30 CFR Part 250 

Continental shelf, Environmental 

impact statements, Environmental 

protection, Government contracts, 

Investigations, Oil and gas exploration, 

Penalties, Pipelines, Public lands—

mineral resources, Public lands—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: 

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

9701. 

2. Amend § 250.105 to revise the 

definition of ‘‘Sensitive reservoir’’ and 

add in alphabetical order definitions for 

‘‘Flaring’’ and ‘‘Venting’’ to read as 

follows: 

§ 250.105 Definitions. 

* * * * * 

Flaring means the burning of gas in 

the field as it is released into the 

atmosphere. 

* * * * * 

Sensitive reservoir means a reservoir 

in which high reservoir production rates 

will decrease ultimate recovery. 

* * * * * 

Venting means the release of gas into 

the atmosphere without igniting it. This 

includes gas that is released underwater 

and bubbles to the atmosphere. 

* * * * * 

3. In § 250.125, revise the table in 

paragraph (a) to read as follows: 

§ 250.125 Service fees. 

(a) * * * 

SERVICE FEE TABLE

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

Change in Designation of Operator ................... $150 ................................................................. § 250.143. 

Suspension of Operations/Suspension of Production (SOO/SOP) Request.$1,800 .............................................................. § 250.171. 

Exploration Plan (EP) ......................................... $3,250 for each surface location, no fee for 

revisions.

§ 250.211. 

Development and Production Plan (DPP) or 

Development Operations Coordination Document (DOCD).

$3,750 for each well proposed, no fee for revisions.§ 250.241(e). 

Deepwater Operations Plan ............................... $3,150 .............................................................. § 250.292(p). 

Conservation Information Document .................. $24,200 ............................................................ § 250.296(a). 

Application for Permit to Drill (APD; Form 

MMS–123).

$1,850.

Initial applications only, no fee for revisions § 250.410(d); § 250.411; § 250.460; 

§ 250.513(b); § 250.515; § 250.1605; 

§ 250.1617(a); § 250.1622. 

Application for Permit to Modify (APM; Form 

MMS–124).

$110 ................................................................. § 250.460; § 250.465(b); § 250.513(b); 

§ 250.515; § 250.613(b); § 250.615; 

§ 250.1618(a); § 250.1622; § 250.1704(g). 

New Facility Production Safety System Application for facility with more than 125 components.$4,750.

A component is a piece of equipment or ancillary system that is protected by one or 

more of the safety devices required by API 

RP 14C (incorporated by reference as 

specified in § 250.198) 

§ 250.802(e). 

(Additional fee of $12,500 will be charged if 

MMS deems it necessary to visit a facility 

offshore; and $6,500 to visit a facility in a 

shipyard) 

New Facility Production Safety System Application for facility with 25–125 components.$1,150 ..............................................................

(Additional fee of $7,850 will be charged if 

MMS deems it necessary to visit a facility 

offshore; and $4,500 to visit a facility in a 

shipyard) 

§ 250.802(e). 

New Facility Production Safety System Application for facility with fewer than 25 components.$570 ................................................................. § 250.802(e). 

Production Safety System Application—Modification with more than 125 components reviewed.$530 ................................................................. § 250.802(e). 

Production Safety System Application—Modification with 25–125 components reviewed.$190 ................................................................. § 250.802(e). 


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SERVICE FEE TABLE—Continued 

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

Production Safety System Application—Modification with fewer than 25 components reviewed.$80 ................................................................... § 250.802(e). 

Platform Application—Installation—under the 

Platform Verification Program.

$19,900 ............................................................ § 250.905(k). 

Platform Application—Installation—Fixed Structure Under the Platform Approval Program.$2,850 .............................................................. § 250.905(k). 

Platform Application—Installation—Caisson/ 

Well Protector.

$1,450 .............................................................. § 250.905(k). 

Platform Application—Modification/Repair ......... $3,400 .............................................................. § 250.905(k). 

New Pipeline Application (Lease Term) ............. $3,100 .............................................................. § 250.1000(b). 

Pipeline Application—Modification (Lease Term) $1,800 .............................................................. § 250.1000(b). 

Pipeline Application—Modification (ROW) ......... $3,650 .............................................................. § 250.1000(b). 

Pipeline Repair Notification ................................ $340 ................................................................. § 250.1008(e). 

Pipeline Right-of-Way (ROW) Grant Application $2,350 .............................................................. § 250.1015. 

Pipeline Conversion of Lease Term to ROW ..... $200 ................................................................. § 250.1015. 

Pipeline ROW Assignment ................................. $170 ................................................................. § 250.1018. 

500 Feet From Lease/Unit Line Production Request.$3,300 .............................................................. § 250.1156. 

Gas Cap Production Request ............................ $4,200 .............................................................. § 250.1157. 

Downhole Commingling Request ....................... $4,900 .............................................................. § 250.1158. 

Complex Surface Commingling and Measurement Application.$3,550 .............................................................. § 250.1202(a); § 250.1203(b); § 250.1204(a). 

Simple Surface Commingling and Measurement 

Application.

$1,200 .............................................................. § 250.1202(a); § 250.1203(b); § 250.1204(a). 

Voluntary Unitization Proposal or Unit Expansion.$10,700 ............................................................ § 250.1303. 

Unitization Revision ............................................ $760 ................................................................. § 250.1303. 

Application to Remove a Platform or Other Facility.$4,100 .............................................................. § 250.1727. 

Application to Decommission a Pipeline (Lease 

Term).

$1,000 .............................................................. § 250.1751(a) or § 250.1752(a). 

Application to Decommission a Pipeline (ROW) $1,900 .............................................................. § 250.1751(a) or § 250.1752(a). 

* * * * * 

4. Revise subpart K to read as follows: 

Subpart K—Oil and Gas Production 

Requirements 

General 

Sec. 

250.1150 What are the general reservoir 

production requirements? 

Well Tests and Surveys 

250.1151 How often must I conduct well 

production tests? 

250.1152 How do I conduct well tests? 

250.1153 When must I conduct a static 

bottomhole pressure survey? 

Classifying Reservoirs 

250.1154 How do I determine if my 

reservoir is sensitive? 

250.1155 What information must I submit 

for sensitive reservoirs? 

Approvals Prior to Production 

250.1156 What steps must I take to receive 

approval to produce within 500 feet of a 

unit or lease line? 

250.1157 How do I receive approval to 

produce gas from an oil reservoir with an 

associated gas cap? 

250.1158 How do I receive approval to 

downhole commingle hydrocarbons? 

Production Rates 

250.1159 May the Regional Supervisor limit 

my well or reservoir production rates? 

Flaring, Venting, and Burning Hydrocarbons 

250.1160 When may I flare or vent gas? 

250.1161 When may I flare or vent gas for 

extended periods of time? 

250.1162 When may I burn produced liquid 

hydrocarbons? 

250.1163 How must I measure gas flaring or 

venting volumes and liquid hydrocarbon 

burning volumes and what records must 

I maintain? 

250.1164 What are the requirements for 

flaring or venting gas containing H2S? 

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 

tests and complete them within the 

specified time period: 

(1) A retest or a prolonged test of a 

well completion if it is determined to be 

necessary for the proper establishment 

of a Maximum Production Rate (MPR) 

or a Maximum Efficient Rate (MER); and 

(2) A multipoint back-pressure test to 

determine the theoretical open-flow 

potential of a gas well. 

(d) An MMS representative may 

witness any well test. Upon request, you 

must provide advance notice to the 

Regional Supervisor of the times and 

dates of well tests. 

§ 250.1153 When must I conduct a static 

bottomhole pressure survey? 

(a) You must conduct a static 

bottomhole pressure survey under the 

following conditions: 

If you have: Then you must conduct: 

(1) A new producing reservoir .................................................................. A static bottomhole pressure survey within 90 days after the date of 

first continuous production. 

(2) A reservoir with three or more producing completions ...................... Annual static bottomhole pressure surveys in a sufficient number of 

key wells to establish an average reservoir pressure. The Regional 

Supervisor may require that bottomhole pressure surveys be performed on specific wells. 

(b) Your bottomhole pressure survey 

must meet the following requirements: 

(1) You must shut-in the well for a 

minimum period of 4 hours to ensure 

stabilized conditions; and 

(2) The bottomhole pressure survey 

must consist of a pressure measurement 

at mid-perforation, and pressure 

measurements and gradient information 

for at least four gradient stops coming 

out of the hole. 

(c) You must submit to the Regional 

Supervisor the results of all static 

bottomhole pressure surveys on Form 

MMS–140, Bottomhole Pressure Survey 

Report, within 60 days after the date of 

the survey. 

(d) The Regional Supervisor may 

grant a departure from the requirement 

to run a static bottomhole pressure 

survey. You must request a departure by 

letter, along with Form MMS–140, 

Bottomhole Pressure Survey Report. 

You must include sufficient justification 

to support the departure request. 

Classifying Reservoirs 

§ 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 

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? 

(a) You must obtain approval from the 

Regional Supervisor before you start 

producing from a well that has any 

portion of the completed interval less 

than 500 feet from a unit or lease line. 

Submit to MMS the service fee listed in 

§ 250.125 and the Regional Supervisor 

will determine whether approval of 

your request will maximize ultimate 

recovery, avoids the waste of natural 

resources or whether it is necessary to 

protect correlative rights. You do not 

need to obtain approval if the adjacent 

leases or units have the same unit, lease, 

and royalty interests as the lease or unit 

you plan to produce. You do not need 

to obtain approval if the adjacent block 

is unleased. 

(b) You must notify the operator(s) of 

adjacent property(ies) that are within 

500 feet of the completion, if the 

adjacent acreage is a leased block in the 

Federal OCS. You must provide the 

Regional Supervisor proof of the date of 

the notification. The operators of the 

adjacent properties have 30 days after 

receiving the notification to provide the 

Regional Supervisor letters of 

acceptance or objection. If an adjacent 

operator does not respond within 30 

days, the Regional Supervisor will 

presume there are no objections and 

proceed with a decision. The 

notification must include: 

(1) The well name; 

(2) The rectangular coordinates (x, y) 

of the location of the top and bottom of 

the completion or target completion 

reference to the North American Datum 

1983, and the subsea depths of the top 

and bottom of the completion or target 

completion; 

(3) The distance from the completion 

or target completion to the unit or lease 

line at its nearest point; and 

(4) A statement indicating whether or 

not it will be a high-capacity completion 

having a perforated or open hole 

interval greater than 150 feet measured 

depth. 

§ 250.1157 How do I receive approval to 

produce gas from an oil reservoir with an 

associated gas cap? 

You must request and receive written 

approval from the Regional Supervisor 

before producing gas from each 

completion in an oil reservoir that is 

known to have an associated gas cap. If 

the oil reservoir is not initially known 

to have an associated gas cap, but your 

oil well begins to show characteristics of 

a gas well, you must request and receive 

written approval from the Regional 

Supervisor to continue producing the 

well. You must include the service fee 

listed in § 250.125 and the supporting 

information, as listed in the table in 

§ 250.1167, with your request. 

§ 250.1158 How do I receive approval to 

downhole commingle hydrocarbons? 

(a) Before you perforate a well, you 

must request and receive approval from 

the Regional Supervisor to commingle 

hydrocarbons produced from multiple 

reservoirs within a common wellbore. 

The Regional Supervisor will determine 

whether your request maximizes 

ultimate recovery and avoids the waste 

of natural resources. You must include 

the service fee listed in § 250.125 and 

the supporting information, as listed in 

the table in § 250.1167, with your 

request. 

(b) If one or more of the commingled 

reservoirs is a competitive reservoir, you 

must notify the operators of all leases 

that contain the reservoir that you 

intend to downhole commingle the 

reservoirs. Your request for approval of 

downhole commingling must include 

proof of the date of this notification. The 

notified operators have 30 days after 

notification to provide the Regional 

Supervisor with letters of acceptance or 

objection. If the notified operators do 

not respond within the specified period, 

the Regional Supervisor will assume the 

operators do not object and proceed 

with a decision. 

Production Rates 

§ 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.

The volume of gas flared or vented may not exceed the amount necessary for its intended purpose. Burning waste products may require 

approval under other regulations. 

(2) During the restart of a facility that was shut in because of weather 

conditions, such as a hurricane.

Flaring or venting may not exceed 48 cumulative hours without Regional Supervisor approval. 

(3) During the blow down of transportation pipelines downstream of the 

royalty meter.

(i) You must report the location, time, flare/vent volume, and reason for 

flaring/venting to the Regional Supervisor in writing within 72 hours 

after the incident is over. 

(ii) Additional approval may be required under subparts H and J of this 

part. 

(4) During the unloading or cleaning of a well, drill-stem testing, production testing, other well-evaluation testing, or the necessary blow 

down to perform these procedures.

You may not exceed 48 cumulative hours of flaring or venting per testing operation on a single completion without Regional Supervisor approval. 

(5) When properly working equipment yields flash gas (natural gas released from liquid hydrocarbons as a result of a decrease in pressure, an increase in temperature, or both) from storage vessels or 

other low-pressure production vessels, and you cannot economically 

recover this flash gas.

You may not flare or vent more than an average 50 MCF per day during any calendar month without Regional Supervisor approval. 


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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. 

(7) When equipment fails to work properly, including equipment maintenance and repair, or when you must relieve system pressures.(i) For oil-well gas and gas-well flash gas, you may not exceed 48 continuous hours of flaring or venting without Regional Supervisor approval. 

(ii) For primary gas-well gas, you may not exceed 2 continuous hours 

of flaring or venting without Regional Supervisor approval. 

(iii) You may not exceed 144 cumulative hours of flaring or venting during a calendar month without Regional Supervisor approval. 

(iv) The continuous and cumulative hours allowed under this paragraph 

may be counted separately from the hours under paragraph (a)(6) of 

this section. 

(b) You must inform the Regional 

Supervisor and receive approval to flare 

or vent gas before you exceed the 

volume specified in your Development 

and Production Plan submitted under 

subpart B of this part, even if the flaring 

or venting does not require approval 

under paragraph (a) of this section. The 

Regional Supervisor will determine 

whether your proposed flaring or 

venting complies with air emission 

thresholds under subpart C of this part. 

(c) The Regional Supervisor may 

establish alternative approval 

procedures to cover situations where 

you cannot contact the MMS office, 

such as during non-office hours. 

(d) The Regional Supervisor may 

specify a volume limit, or a shorter time 

limit than specified elsewhere in this 

part, in order to prevent air quality 

degradation or loss of reserves. 

(e) The Regional Supervisor will 

evaluate your request for gas flaring or 

venting and determine if the loss of 

hydrocarbons is due to negligence, or 

could be avoided. 

(f) If you flare or vent gas without the 

required approval, or if the Regional 

Supervisor determines that you were 

negligent or could have avoided flaring 

or venting the gas, the hydrocarbons 

will be considered avoidably lost or 

wasted. You must pay royalties on the 

loss or waste, according to part 202 of 

this title. You must value any gas or 

liquid hydrocarbons avoidably lost or 

wasted under the provisions of part 206 

of this title. 

§ 250.1161 When may I flare or vent gas 

for extended periods of time? 

You may flare or vent oil-well gas and 

gas-well flash gas for a period that the 

Regional Supervisor will specify, and 

which will not exceed 1 year, if the 

Regional Supervisor approves your 

request for one of the following reasons: 

(a) You initiate an action which, when 

completed, will eliminate flaring and 

venting; 

(b) You submit to the Regional 

Supervisor an evaluation supported by 

engineering, geologic, and economic 

data indicating that the oil and gas 

produced from the well(s) will not 

economically support the facilities 

necessary to sell the gas; or to use the 

gas on or for the benefit of, the lease; or 

(c) The Regional Supervisor 

determines that an improperly working 

valve, pipe fitting, or similar component 

results in flaring or venting of less than 

10 MCF per day, and that it is prudent 

to repair the leak at a later date. The 

Regional Supervisor may exempt this 

flaring or venting from the time limits 

set in § 250.1160. 

§ 250.1162 When may I burn produced 

liquid hydrocarbons? 

(a) You must request and receive 

approval from the Regional Supervisor 

to burn any produced liquid 

hydrocarbons. The Regional Supervisor 

may allow you to burn condensate if 

you demonstrate that transporting it to 

market or re-injecting it is not feasible 

or poses a significant risk of harm to 

offshore personnel or the environment. 

In most cases, the Regional Supervisor 

will not allow you to burn more than 

300 barrels of condensate in total during 

unloading or cleaning of a well, 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 

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 9899 

(1) You must report the amount of gas 

flared and the amount of gas vented 

separately. 

(2) You may classify and report gas 

used to operate equipment on the 

facility (such as gas used to power 

engines, gas used as pilot lights, 

instrument gas, purge gas used to 

prevent oxygen from entering the flare 

or vent stack, sparge gas used to 

regenerate glycol, and blanket gas used 

to maintain pressure in low pressure 

vessels) as lease use gas. 

(3) You must report the amount of gas 

flared and vented at each facility on a 

lease or unit basis. Gas flared and 

vented from multiple facilities on a 

single lease or unit must be reported 

separately. 

(c) You must prepare and maintain 

records detailing gas flaring, gas 

venting, and liquid hydrocarbon 

burning for each facility. You must 

maintain these records for the period 

specified in part 212 of this title. You 

must keep these records on the facility 

for 2 years and have them available for 

inspection by MMS representatives. 

After 2 years, you must maintain the 

records, allow MMS representatives to 

inspect the records upon request, and 

provide copies to the Regional 

Supervisor upon request, but you are 

not required to keep them on the 

facility. The records must include, at a 

minimum: 

(1) Daily volumes of gas flared, gas 

vented, and liquid hydrocarbons 

burned; 

(2) Number of hours of gas flaring, gas 

venting, and liquid hydrocarbon 

burning, on a daily basis; 

(3) A list of the wells contributing to 

gas flaring, gas venting, and liquid 

hydrocarbon burning, along with gas-oil 

ratio data; 

(4) Reasons for gas flaring, gas 

venting, and liquid hydrocarbon 

burning; and 

(5) Documentation of all required 

approvals. 

(d) If your facility is required to have 

flare/vent meters, you must maintain 

the meter recordings for the period 

specified in §§ 212.50 and 212.51 of this 

title. You must keep these recordings on 

the facility for 2 years and have them 

available for inspection by MMS 

representatives. After 2 years, you must 

maintain the recordings, allow MMS 

representatives to inspect the recordings 

upon request, and provide copies to the 

Regional Supervisor upon request, but 

are not required to keep them on the 

facility. These recordings must include 

the begin times, end times, and volumes 

for all flaring and venting incidents. 

(e) If your flaring or venting of gas, or 

burning of liquid hydrocarbons, 

required written or oral approval, you 

must submit documentation to the 

Regional Supervisor summarizing the 

location, dates, number of hours, and 

volumes of gas flared, gas vented, and 

liquid hydrocarbons burned under the 

approval, as required under § 250.140. 

§ 250.1164 What are the requirements for 

flaring or venting gas containing 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 

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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9900 Federal Register / Vol. 72, No. 43 / Tuesday, March 6, 2007 / Proposed Rules 

WPT MMS–

126 SRI MMS–127 Gas cap production 

Downhole 

commingling 

Reservoir 

reclassification 

Production 

within 500-ft of 

a Unit or 

Lease Line 

(a) Maps: 

(1) Base map with surface, 

bottomhole, and completion locations with respect to the unit or 

lease line and the orientation of 

representative seismic lines or 

cross sections ............................... ........................ ........................ ✓ ✓ ........................ ✓ 

(2) Structure maps with penetration 

point and subsea depth for each 

well penetrating the reservoirs, 

highlighting subject wells; reservoir boundaries; and original 

and current fluid levels .................. ✓ ✓ ✓ ✓ ✓ ✓ 

(3) Net sand isopach with total net 

sand penetrated for each well, 

identified at the penetration point ........................ ✓ ✓ ✓ ........................ ........................

(4) Net hydrocarbon isopach with 

net feet of pay for each well, identified at the penetration point ........ ........................ ✓ ✓ ✓ ........................ ........................

(b) Seismic data: 

(1) Representative seismic lines, including strike and dip lines that 

confirm the structure; indicate polarity ............................................... ........................ ........................ ✓ ✓ ........................ ✓ 

(2) 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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Federal Register / Vol. 72, No. 43 / Tuesday, March 6, 2007 / Proposed Rules 9901 

WPT MMS–

126 SRI MMS–127 Gas cap production 

Downhole 

commingling 

Reservoir 

reclassification 

Production 

within 500-ft of 

a Unit or 

Lease Line 

(6) List of all wells in subject reservoirs that have ever produced or 

been used for injection .................. ........................ ........................ ✓ ✓ ✓ ✓ 

†Each Gas Cap Production request and Downhole Commingling request should include the estimated recoverable reserves for (1) the case 

where your proposed production scenario is approved, and (2) the case where your proposed production scenario is denied. 

* Additional items the Regional Supervisor may request. 

Note: All maps must be at a standard scale and show lease and unit lines. If you have not generated all of the required data for your own purposes, you may submit those data you have available for consideration. 

(f) Depending on the above 

requirement, you must submit 

appropriate payment of the service 

fee(s) listed in § 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 

AGENCY: Coast Guard, DHS. 

ACTION: Notice of proposed rulemaking. 

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 

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 24- 

hour Command Center at (415) 399–

3547. 

SUPPLEMENTARY INFORMATION: 

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 

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 


cprice-sewell on PROD1PC67 with PROPOSALS