Federal Register / Vol. 62, No. 38 / Wednesday, February 26, 1997 / Proposed Rules 8665

SUMMARY: This document contains

corrections to the proposed regulations

which were published Friday, July 5,

1996 (61 FR 35158). The proposed rule

amends regulations governing Courts of

Indian Offenses.

DATES: Comments must be received on

or before March 28, 1997.

ADDRESSES: Comments are to be mailed

to Bettie Rushing, Office of Tribal

Services, Bureau of Indian Affairs, 1849

C Street, NW, MS 4641–MIB,

Washington, DC 20240; or, hand

delivered to Room 4641 at the same

address.

FOR FURTHER INFORMATION CONTACT:

Bettie Rushing, Bureau of Indian Affairs

(202) 208–4400.

SUPPLEMENTARY INFORMATION:

Background

The proposed rule that is the subject

of these corrections supersedes 25 CFR

11.100(a) and affects those tribes that

have exercised their inherent

sovereignty by removing the names of

those tribes from the list of Courts of

Indian Offenses.

The Assistant Secretary-Indian

Affairs, or her designee, has received

law and order codes adopted by the

Lovelock Paiute Tribe of Nevada, the

Absentee Shawnee Tribe of Indians of

Oklahoma, the Cheyenne-Arapaho

Tribes of Oklahoma, the Citizen

Potawatomi Nation, the Iowa Tribe of

Oklahoma, the Kaw Nation, the

Kickapoo Tribe of Oklahoma, the OtoeMissouria Tribe of Indians, the Pawnee

Indian Tribe of Oklahoma, and the

Osage Indian Nation (except those

matters involving the Osage mineral

estate) in accordance with their

constitutions and by-laws and approved

by the appropriate bureau official. The

Assistant Secretary-Indian Affairs

recognizes that these courts were

established in accordance with the

tribes’ constitutions and by-laws.

Inclusion in § 11.100, Where are

Courts of Indian Offenses established?,

does not defeat the inherent sovereignty

of a tribe to establish tribal courts and

exercise jurisdiction under tribal law.

Tillett v. Lujan, 931 F.2d 636, 640 (10th

Cir. 1991) (CFR courts ‘‘retain some

characteristics of an agency of the

federal government’’ but they ‘‘also

function as tribal courts’’); Combrink v.

Allen, 20 Indian L. Rep. 6029, 6030 (Ct.

Ind. App., Tonkawa, Mar. 5, 1993) (CFR

court is a ‘‘federally administered tribal

court’’); Ponca Tribal Election Board v.

Snake, 17 Indian L. Rep. 6085, 6088 (Ct.

Ind. App., Ponca, Nov. 10, 1988) (‘‘The

Courts of Indian Offenses act as tribal

courts since they are exercising the

sovereign authority of the tribe for

which the court sits.’’). Such exercise of

inherent sovereignty and the

establishment of tribal courts shall

comply with the requirements in 25

CFR 11.100(c).

Need for Correction

As published, the proposed rule

contains errors which may prove to be

misleading and are in need of

clarification.

Correction of Publication

Accordingly, the publication on July

5, 1996 of the proposed regulations,

which were the subject of FR Doc. 96–

16039, is corrected as follows:

§ 11.100 [Corrected]

1. On page 35159 in the third column

and on page 35160 in the first column

paragraph (a) is corrected to read as

follows:

§ 11.100 Where are Courts of Indian

Offenses established?

(a) Unless indicated otherwise in this

title, the regulations in this part apply

to the Indian country (as defined in 18

U.S.C. 1151) occupied by the following

tribes:

(1) Red Lake Band of Chippewa

Indians (Minnesota).

(2) Confederated Tribes of the

Goshute Reservation (Nevada).

(3) Te-Moak Band of Western

Shoshone Indians (Nevada).

(4) Yomba Shoshone Tribe (Nevada).

(5) Kootenai Tribe (Idaho).

(6) Shoalwater Bay Tribe

(Washington).

(7) Eastern Band of Cherokee Indians

(North Carolina).

(8) Ute Mountain Ute Tribe

(Colorado).

(9) Quechan Indian Tribe (Arizona)

(Except resident members).

(10) Valley Tribe, Yurok Tribe, and

Coast Indian Community of California

(California Jurisdiction limited to

special fishing regulations).

(11) Louisiana Area (includes

Coushatta and other tribes located in the

State of Louisiana which occupy Indian

and which accept the application of this

part); Provided that this part shall not

apply to any Louisiana tribe other than

the Coushatta Tribe until notice of such

application has been published in the

Federal Register.

(12) For the following tribes located in

the former Indian Territory (Oklahoma):

(i) Chickasaw Nation.

(ii) Choctaw Nation.

(iii) Thlopthlocco Tribal Town.

(iv) Seminole Nation.

(v) Eastern Shawnee Tribe.

(vi) Miami Tribe.

(vii) Modoc Tribe.

(viii) Ottawa Tribe.

(ix) Peoria Tribe.

(x) Quapaw Tribe.

(xi) Wyandotte Tribe.

(xii) Seneca-Cayuga Tribe.

(xiii) Osage Tribe (Limited to mineral

estate matters).

* * * * *

Dated: February 14, 1997.

Ada E. Deer,

Assistant Secretary—Indian Affairs.

[FR Doc. 97–4686 Filed 2–25–97; 8:45 am]

BILLING CODE 4310–22–P

Minerals Management Service

30 CFR Part 250

RIN 1010–AB97

Oil and Gas Production Measurement,

Surface Commingling, and Security

AGENCY: Minerals Management Service

(MMS), Interior.

ACTION: Proposed rule.

SUMMARY: This proposed rule would

amend MMS regulations governing oil

and gas operations in the Outer

Continental Shelf (OCS) to update

production measurement and surface

commingling requirements. The MMS

needs this rule to help ensure that gas

produced in the OCS is accurately

measured and reported.

DATES: MMS will consider all comments

received by May 27, 1997. We will begin

reviewing comments at that time and

may not fully consider comments we

receive after May 27, 1997.

ADDRESSES: Mail or hand-carry

comments to the Department of the

Interior; Minerals Management Service;

Mail Stop 4700; 381 Elden Street;

Herndon, Virginia 20170–4817;

Attention: Rules Processing Team.

FOR FURTHER INFORMATION CONTACT:

Sharon Buffington, Engineering and

Research Branch, at (703) 787–1147.

SUPPLEMENTARY INFORMATION: Pipeline

and price deregulation and open access

to pipelines that occurred in the late

1980’s spawned a restructuring of OCS

pipeline system operations. Pipeline

companies traditionally were merchants

buying and selling gas under long-term

contracts to only a few well established

customers. Under the Federal Energy

Regulatory Commission Order 636,

pipeline companies operate as common

carriers involved in transportation

services to a broad spectrum of gas

producers, end users, and transportation

brokers. Also, the OCS pipeline systems

have hundreds of short-term, limited

volume contracts, many of which

require daily accounting and balance

controls.
8666 Federal Register / Vol. 62, No. 38 / Wednesday, February 26, 1997 / Proposed Rules

Because of the restructuring and

complexity in pipeline operating

systems and the increasing use and

value of natural gas, the accuracy and

reliability of meters have become even

more important to ensuring product

accountability and fiscal responsibility.

Therefore, industry has initiated

production measurement research that

resulted in more precise metering and

data collection equipment.

Most of the production in the OCS is

natural gas and a 1 percent

measurement or reporting uncertainty

could result in royalty revenue

variations of $15 million per year. MMS

is responsible for ensuring accurate

production measurement and reporting.

The gas measurement and

commingling regulations now in effect

were based on conditions before

deregulation and before the industry

began to apply the results of research

efforts. Therefore, MMS is proposing to

amend the production measurement and

commingling regulations. The

regulatory revisions proposed in this

rule would:

• Reflect current industry technology,

• Form the basis for a gas verification

system (GVS),

• Require tracking of gas lost or used

on the lease, and

• Clarify the restrictions on surface

commingling.

The liquid measurement regulations

of 1988 already give the guidance for

our liquid verification system.

Therefore, MMS is not proposing

technical changes to liquid

measurement; we are only clarifying the

language.

On June 23, 1994, a meeting was held

at the Department of the Interior (DOI)

in Washington, D.C., to introduce the oil

and gas industry to the principles of this

rulemaking and the proposed GVS. The

participants generally agreed that the

regulations on production measurement

should be updated to include current

industry standards. The main items

discussed at the meeting are as follows:

1. If MMS verifies gas production and

also conducts audits, it appears that

industry is under a double jeopardy.

Currently, MMS only audits some OCS

gas production. MMS is proposing to

supplement the audits by implementing

a limited gas verification program that

will create a system to quickly check

submitted gas production volumes with

gas volume statements. MMS will

coordinate gas verification and the

royalty audit programs.

2. Why does MMS want daily

production data on the gas volume

statements to verify production reported

monthly? While daily production data is

easier to obtain from electronically

measured data than from chart

recorders, it appears that meter owners

provide gas producers (lessees) a daily

breakout of gas production once a

month. Daily production data is the best

data to use to verify gas production.

3. How will MMS verify gas that is

processed before royalty is calculated?

MMS will use the monthly statement

that gas plant managers supply to

producers instead of the gas volume

statement. However, if these statements

are not prepared on a daily basis for the

month, MMS may ask for additional

data from the lessee to verify

production.

4. MMS is seeking comments

concerning whether you receive

monthly gas measurement statements

from meter owners that show a daily

summary of volumes and quality. If you

do not receive the statements, please list

how you audit the production records.

5. MMS is seeking comments on the

applicable industry standards and

practices that we incorporate and

exclude. This proposed rule would

require that lessees follow the standards

listed in 30 CFR 250.1, Documents

Incorporated by Reference. MMS

published that final rule on November

26, 1996, (61 FR 60019).

6. This proposed rule would require

seals only on liquid hydrocarbon royalty

installations. However, MMS may also

require seals on gas installations in the

final rule. Please comment on this

proposal.

7. MMS is also seeking comments on

the type of records you keep for gas

used on the lease, how you record

volumes and quality, and how you

measure or estimate volumes and

quality.

Executive Order (E.O.) 12866

DOI has certified that this proposed

rule is not a significant rule under E.O.

12866.

E.O. 12988

DOI has certified to the Office of

Management and Budget (OMB) that the

rule meets the applicable reform

standards provided in sections 3(a) and

3(b)(2) of E.O. 12988.

Unfunded Mandates Reform Act of

1995

DOI has determined and certifies

according to the Unfunded Mandates

Reform Act, 2 U.S.C. 1502 et seq., that

this rule will not impose a cost of $100

million or more in any year on State,

local, and tribal governments, or the

private sector.

Regulatory Flexibility Act

The DOI has determined that this

proposed rule will not have a significant

economic effect on a substantial number

of small entities.

Paperwork Reduction Act

This proposed rule contains a

collection of information which has

been submitted to OMB for review and

approval under section 3507(d) of the

Paperwork Reduction Act of 1995. As

part of our continuing effort to reduce

paperwork and respondent burden,

MMS invites the public and other

Federal agencies to comment on any

aspect of the reporting burden. Submit

your comments to the Office of

Information and Regulatory Affairs;

OMB; Attention Desk Officer for the

Department of the Interior, 725 17th

Street NW, Washington, D.C. 20503

(OMB control number 1010–0051). Send

a copy of your comments to the Chief,

Engineering and Standards Branch; Mail

Stop 4700; Minerals Management

Service; 381 Elden Street; Herndon,

Virginia 20170–4817. You may obtain a

copy of the proposed collection of

information by contacting the Bureau’s

Information Collection Clearance Officer

at (703) 787–1242.

OMB may make a decision to approve

or disapprove this collection of

information after 30 days from receipt of

our request. Therefore, your comments

are best assured of being considered by

OMB if OMB receives them within that

time period. However, MMS will

consider all comments received during

the comment period for this notice of

proposed rulemaking.

The title of this collection of

information is ‘‘30 CFR 250, Subpart L,

Oil and Gas Production Measurement,

Surface Commingling, and Security.’’

OMB previously approved it under

OMB control number 1010–0051.

The collection of information consists

of oil run tickets; proving and

calibrations reports; measuring liquid

hydrocarbons and gas; applications for

surface commingling, and various

recordkeeping requirements. The

proposed rule would delete some

recordkeeping and reporting

requirements. it would add the

following when required by the

Regional Supervisor:

• Gas volume statements,

• Production quality data, and

• Data concerning gas lost or used on

the lease.

MMS would use the information to

verify production measurements.

Respondents are Federal OCS oil, gas,

and sulphur lessees. MMS will receive

approximately 2,300 new responses
Federal Register / Vol. 62, No. 38 / Wednesday, February 26, 1997 / Proposed Rules 8667

each year. The frequency of submission

varies.

MMS estimates the additional annual

reporting burden as a result of this rule

would be approximately 192 hours (.08

hour per response). We estimate the

total annual burden to be 2,615

reporting hours and 2,429

recordkeeping hours. Based on $35 per

hour, the total burden hour cost to

respondents is estimated to be $176,540.

In calculating the burden, MMS

assumed that respondents perform

many of the requirements and maintain

records in the normal course of their

activities. MMS considers these to be

usual and customary and did not

include them in the burden estimates.

Commenters are invited to provide

information if they disagree with this

assumption and they should tell us

what are the burden hours and costs

imposed by this collection of

information.

MMS will summarize written

responses to this notice and address

them in the final rule. All comments

will become a matter of public record.

1. MMS specifically solicits

comments on the following questions:

(a) Is the proposed collection of

information necessary for the proper

performance of MMS’s functions, and

will it be useful?

(b) Are the estimates of the burden

hours of the proposed collection

reasonable?

(c) Do you have any suggestions that

would enhance the quality, clarity, or

usefulness of the information to be

collected?

(d) Is there a way to minimize the

information collection burden on those

who are to respond, including through

the use of appropriate automated

electronic, mechanical, or other forms of

information technology?

2. In addition, the Paperwork

Reduction Act of 1995 requires agencies

to estimate the total annual cost burden

to respondents or recordkeepers

resulting from the collection of

information. MMS needs your

comments on this item. Your response

should split the cost estimate into two

components:

(a) Total capital and startup cost and

(b) Annual operation, maintenance,

and purchase of services.

Your estimates should consider the

costs to generate, maintain, and 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 startup 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, your 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.

The Paperwork Reduction Act of 1995

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.

Takings Implication Assessment

DOI certifies that the proposed rule

does not represent a governmental

action capable of interference with

constitutionally protected property

rights. Thus, a Takings Implication

Assessment need not be prepared

pursuant to E.O. 12630, Government

Action and Interference with

Constitutionally Protected Property

Rights.

National Environmental Policy Act

DOI determined that this rulemaking

does not constitute a major Federal

action significantly affecting quality of

the human environment; therefore, an

Environmental Impact Statement is not

required.

List of Subjects in 30 CFR Part 250

Continental shelf, Environmental

impact statements, Environmental

protection, Government contracts,

Incorporation by reference,

Investigations, Mineral royalties, Oil

and gas development and production,

Oil and gas exploration, Oil and gas

reserves, Penalties, Pipelines, Natural

gas, Petroleum, Public lands—mineral

resources, Public lands—rights-of-way,

Reporting and recordkeeping

requirements, Sulphur development and

production, Sulphur exploration, Surety

bonds.

Dated: December 30, 1996.

Bob Armstrong,

Assistant Secretary, Land and Minerals

Management.

For the reasons in the preamble, the

Minerals Management Service (MMS)

proposes to amend 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. 1334.

2. Subpart L is revised to read as

follows:

Subpart L—Oil and Gas Production

Measurement, Surface Commingling, and

Security

Sec.

250.180 Question index table.

250.181 Definitions for Subpart L.

250.182 Liquid Hydrocarbon measurement.

250.183 Gas measurement.

250.184 Surface commingling.

250.185 Site security.

250.186 Measuring gas lost or used on a

lease.

Subpart L—Oil and Gas Production

Measurement, Surface Commingling,

and Security

§ 250.180 Question Index Table

The table in this section lists

questions concerning Oil and Gas

Production Measurement, Surface

Commingling, and Security and the

location of the answers.

Frequently asked questions CFR citation

1. What are the requirements for measuring liquid hydrocarbons? ................................................................................................... § 250.182 (a).

2. What are the requirements for liquid hydrocarbon royalty meters? .............................................................................................. § 250.182 (b).

3. What are the requirements for run tickets? ................................................................................................................................... § 250.182 (c).

4. What are the requirements for liquid hydrocarbon royalty meter provings? ................................................................................. § 250.182 (d).

5. What are the requirements for a master meter and its calibration? .............................................................................................. § 250.182 (e).

6. What are the requirements for calibrating mechanical-displacement provers and tank provers? ................................................ § 250.182 (f).

7. What correction factors must a lessee account for when calibrating meters with a mechanical displacement prover, tank

provers or master meter?.

§ 250.182 (g).

8. What are the requirements for establishing and applying operating meter factors for liquid hydrocarbons? ............................... § 250.182 (h).

9. Under what circumstances does MMS consider that a liquid hydrocarbon royalty meter failed and what must a lessee do? ... § 250.182 (i).
8668 Federal Register / Vol. 62, No. 38 / Wednesday, February 26, 1997 / Proposed Rules

Frequently asked questions CFR citation

10. How must a lessee correct gross liquid hydrocarbon volumes measured under nonstandard conditions? ............................... § 250.182 (j).

11. What are the requirements for liquid hydrocarbon allocation meters? ........................................................................................ § 250.182 (k).

12. What are the requirements for tank facilities designated as a royalty point? ............................................................................. § 250.182 (l).

13. To which meters do MMS requirements for gas measurement apply? ....................................................................................... § 250.183 (a).

14. What are the requirements for measuring gas? .......................................................................................................................... § 250.183 (b).

15. What are the requirements for gas meter calibrations? .............................................................................................................. § 250.183 (c).

16. What must a lessee do if a gas meter is malfunctioning? ........................................................................................................... § 250.183 (d).

17. What are the requirements when natural gas from a Federal lease is delivered to a gas plant? .............................................. § 250.183 (e).

18. What are the requirements when commingling production at the surface? ................................................................................ § 250.184 (a).

19. What are the requirements for a well test used for allocation? ................................................................................................... § 250.184 (b).

20. What are the requirements for site security? ............................................................................................................................... § 250.185 (a).

21. What are the requirements for using seals? ................................................................................................................................ § 250.185 (b).

22. What are the requirements for measuring gas lost or used on a lease? .................................................................................... § 250.186.

§ 250.181 Definitions for subpart L.

Terms used in Subpart L have the

following meaning:

Allocation meter means a meter

whose volume measurement

substantiates which portion of the

volume measured by a royalty meter is

attributable to a particular lease, unit,

well, or other measurement point.

API MPMS means the American

Petroleum Institute’s Manual of

Petroleum Measurement Standards.

British Thermal Unit (Btu) means the

amount of heat needed to raise the

temperature of one pound of water by 1

degree Fahrenheit (1°F) at standard

atmospheric pressure.

Calibration means the adjustment or

standardization of a measuring

instrument to yield precise data.

Fractional Analysis means separating

mixtures into identifiable components

expressed in mole percent.

Gas meter means an approved meter

that measures natural gas and upon

which MMS bases royalty and/or

allocation volumes.

Gas processing plant means an

installation for processing natural gas to

remove impurities and recover natural

gas liquids (NGL’s) and other products.

The NGL’s are reported as the sum of

the products (ethane, propane, butane,

and natural gasoline) on the report of

sales and royalty remittance. Products

like nitrogen, sulphur, carbon dioxide

and helium are reported separately.

Gas processing plant statement means

a monthly statement showing the

volume and quality of the inlet gas

stream and the plant products recovered

during the period, volume of deductible

plant fuel, and the allocation of plant

products to the sources of the inlet

stream.

Gas royalty meter malfunction means

an error in the gas measurement device

that exceeds manufacturers

specifications.

Gas volume statement means a

document prepared by the owner of a

gas meter that identifies the volume of

natural gas measured by the meter. The

statement contains information such as

pressure base, temperature base, and

volumetric data in a thousand cubic feet

(Mcf) and quality data in gross Btu’s per

cubic foot.

Liquid hydrocarbons (free liquids)

mean a mixture of hydrocarbons

produced in liquid form after passing

through surface separating facilities.

Malfunction factor means a liquid

hydrocarbon royalty meter factor that

differs from the previous meter factor by

an amount greater than 0.0025.

Natural gas means all components of

a whole natural gas stream which pass

a meter in vapor phase at the

measurement point.

Natural gas liquids (NGL’s) mean

components of natural gas that are

liquefied from the whole gas stream and

extracted in gas processing plants.

Operating meter means a meter that is

used for measurement at any time

during the month. A meter must be

proved or calibrated only if it is an

operating meter.

Pressure base means the pressure at

which gas volumes are reported. The

standard pressure base for converting

measured volumes to standard volumes

is 14.73 pounds per square inch

absolute (psia).

Prove means to determine the

accuracy of a meter, usually by running

a known quantity (or quantities) of

hydrocarbon through the meter at a

known temperature and pressure while

recording the meter volume registration.

Retrograde condensate means liquid

hydrocarbons that drop out of the

separated gas stream at any point prior

to entering a gas processing plant, but

after the facility measurement point.

Royalty meter means an approved

meter that measures natural gas or

liquid hydrocarbons and upon which

MMS bases royalty volumes.

Run ticket means the invoice for

liquid hydrocarbons measured at a

royalty point.

Sales meter means a meter at which

custody transfer takes place (not

necessarily a royalty meter).

Seal means a device or approved

method used to prevent tampering with

measurement facility components.

Standard conditions means 14.73

pounds per square inch absolute (psia)

and 60° F.

Surface commingling means the

surface mixing of production from two

or more leases or units prior to

measurement for royalty purposes.

Temperature base means the

temperature at which gas volumes are

reported. The standard temperature base

for use in converting measured volumes

to standard volumes is 60° F.

You or your means the lessee or

contractor engaged in operations in the

Outer Continental Shelf (OCS).

§ 250.182 Liquid hydrocarbon

measurement.

(a) What are the requirements for

measuring liquid hydrocarbons? Lessees

must:

(1) Commence liquid hydrocarbon

production or make changes to

previously approved measurement

procedures only after the Regional

Supervisor has approved the liquid

hydrocarbon application or changes to

an existing approval;

(2) Use measurement equipment that

will accurately measure the liquid

hydrocarbons produced from a lease or

unit;

(3) Use procedures and correction

factors according to the applicable

chapters of the API MPMS as referenced

in 30 CFR 250.1 when obtaining net

standard volume and associated

measurement parameters; and

(4) When requested by the Regional

Supervisor, determine the retrograde

condensate volume and allocate it back

to the individual leases and/or units and

wells.

(b) What are the requirements for

liquid hydrocarbon royalty meters?

Lessees must:

(1) Ensure that the royalty meter

facilities include the following

components (or other MMS-approved
Federal Register / Vol. 62, No. 38 / Wednesday, February 26, 1997 / Proposed Rules 8669

components) which must be compatible

with their connected systems:

(i) A positive-displacement meter

equipped with a nonreset totalizer;

(ii) A mechanical displacement

prover, a master meter, a calibrated tank

prover;

(iii) A proportional-to-flow sampling

device pulsed by the meter output; and

(iv) A temperature measurement or

temperature compensation device.

(2) Ensure that the royalty meter

facilities accomplish the following:

(i) Prevent flow reversal through the

meter;

(ii) Protect meters subjected to

pressure pulsations or surges;

(iii) Prevent the meter from shock

pressures greater than the maximum

working pressure; and

(iv) Prevent meter bypassing.

(3) Maintain royalty meter facilities to

ensure the following:

(i) Meters operate within the gravity

range specified by the manufacturer;

(ii) Meters operate within the

manufacturer’s specifications for

maximum and minimum flow rate for

linear accuracy; and

(iii) Meters are reproven when

changes in metering conditions affect

the meters performance such as changes

in pressure, temperature, density (water

content), viscosity, pressure, and flow

rate.

(4) Ensure that sampling devices

conform to the following:

(i) The sampling point is in the

flowstream immediately upstream or

downstream of the meter or divert valve;

(ii) The sample container is vaportight and includes a mixing device to

allow complete mixing of the sample

before removal from the container; and

(iii) The sample probe is in the center

of the flow piping in a vertical run and

is located at least three pipe diameters

downstream of any pipe fitting within a

region of turbulent flow.

(c) What are the requirements for run

tickets? Lessees must:

(1) Send all run tickets pulled and/or

completed to the Regional Supervisor

within 15 days following the end of the

month;

(2) Pull a run ticket when establishing

the monthly meter factor or a

malfunction meter factor. Send the

Regional Supervisor a copy of this run

ticket; and

(3) Ensure that run tickets clearly

identify all observed data, all correction

factors not included in the meter factor,

the net standard volume, and all

calculations and factors.

(d) What are the requirements for

liquid hydrocarbon royalty meter

provings? Lessees must:

(1) Permit MMS representatives to

witness regularly scheduled provings or

any proving requested by the Regional

Supervisor;

(2) Ensure that the integrity of the

prover calibration is traceable to test

measures certified by the National

Institute of Standards and Technology;

(3) Prove each operating royalty meter

to determine the meter factor during

each month but the time between meter

factor determinations must not exceed

42 days; and

(4) Submit copies of all meter proving

reports for royalty meters to the

Regional Supervisor monthly within 15

days after the end of the month.

(e) What are the requirements for a

master meter and its calibration?

Lessees must:

(1) Calibrate the master meter to

obtain a meter factor before using it to

determine operating meter factors;

(2) Use a fluid of similar gravity,

viscosity, temperature, and flow rate as

the liquid hydrocarbons that flow

through the operating meter to calibrate

the master meter;

(3) Calibrate the master meter during

each month but the time between

calibrations must not exceed 42 days;

(4) Calibrate the master meter by

recording runs until the results of two

consecutive runs (if a tank prover is

used) or five out of six consecutive runs

(if a mechanical-displacement prover is

used) produce maximum meter factor

differences of 0.0002. Lessees must use

the average of the two (or the five) runs

that produced acceptable results to

compute the master meter factor; and

(5) Install the master meter upstream

of any back-pressure or reverse flow

check valves associated with the

operating meter. However, you may

install master meters either upstream or

downstream of the operating meter.

(6) Keep a copy of the master meter

proving report at your field location for

2 years.

(f) What are the requirements for

calibrating mechanical-displacement

provers and tank provers? Lessees must:

(1) Calibrate mechanical-displacement

provers and tank provers at least once

every 5 years according to the API

MPMS as referenced in 30 CFR 250.1;

and

(2) Submit a copy of each calibration

report to the Regional Supervisor within

15 days after the calibration.

(g) What correction factors must a

lessee account for when calibrating

meters with a mechanical-displacement

prover, tank prover, or master meter?

Use the following correction factors

from the API MPMS as referenced in 30

CFR 250.1:

(1) The change in prover volume due

to pressure in the steel pipe (Cps);

(2) The change in volume of the test

liquid with the change in temperature

(Ctl);

(3) The change in prover volume due

to the change in temperature (Cts); and

(4) The change in volume of the test

liquid with the change in pressure (Cpl).

(h) What are the requirements for

establishing and applying operating

meter factors for liquid hydrocarbons?

(1) If you use a mechanicaldisplacement prover, you must record

proof runs until five out of six

consecutive runs produce a maximum

difference between individual runs of

.0005. You must use the average of the

five runs to compute the meter factor.

(2) If you use a master meter, you

must record proof runs until three

consecutive runs produce a maximum

total meter factor difference of 0.0005.

The volume of each run must be at least

10 percent of the hourly rated capacity

of the operating meter. You must use the

average of the three runs to compute the

meter factor.

(3) If you use a tank prover, you must

record proof funs until two consecutive

runs produce a maximum meter factor

difference of .05 percent of the tank

prover volume. You must use the

average of the two consecutive runs to

compute the meter factor.

(4) You must apply meter factors that

are within tolerance starting with the

date of the proving.

(i) Under what circumstances does

MMS consider that a liquid hydrocarbon

royalty meter failed and what must a

lessee do?

(1) If the difference between the meter

factor and the previous factor exceeds

0.0025 it is a malfunction factor and

lessees must do the following:

(i) Remove the meter from service and

check it for damage and/or wear;

(ii) Adjust it and/or repair it, and

reprove it;

(iii) Apply the average of the

malfunction factor and the previous

factor to the production measured

through the meter between the date of

the previous factor and the date of the

malfunction factor; and

(iv) Show all appropriate remarks

regarding subsequent repairs and/or

adjustments on the proving report.

(2) If a meter fails to register

production the lessee must do the

following:

(i) Remove the meter from service,

repair and reprove it;

(ii) Apply the previous meter factor to

the production run between the date of

that factor and the date of the failure;

and

(iii) Estimate unregistered production

by the best possible means and report it

as estimated production on the proving

report.
8670 Federal Register / Vol. 62, No. 38 / Wednesday, February 26, 1997 / Proposed Rules

(3) If the results of a royalty meter

proving exceed the run tolerance criteria

and all measures excluding the

adjustment and/or repair of the meter

can’t bring results within tolerance the

lessees must:

(i) Establish a factor using proving

results made before any adjustment and/

or repair of the meter; and

(ii) Treat the established factor like a

malfunction factor [See paragraph (i)(1)

of this section].

(j) How must a lessee correct gross

liquid hydrocarbon volumes measured

under nonstandard condition?

(1) Calculate Cpl factors into the

meter factor or list and apply them on

the appropriate run ticket.

(2) List the Ctl factors on the

appropriate run ticket when the meter is

not automatically temperature

compensated.

(k) What are the requirements for

liquid hydrocarbon allocation meters?

Lessees must:

(1) Take samples continuously or

daily;

(2) For turbine meters, take the

sample proportional to the flow;

(3) Prove allocation meters monthly if

they measure 50 or more barrels of oil

per day per meter; or

(4) Prove allocation meters quarterly if

they measure less than 50 barrels of oil

per day per meter;

(5) Keep a copy of the proving reports

at the field location for 2 years;

(6) Adjust and reprove the meter if a

meter factor differs from the previous

meter factor by more than 2 percent and

less than 7 percent;

(7) For turbine meters, inspect the

meter if a factor differs from the

previous meter factor by more than 2

percent and less than 7 percent; and

(8) Repair or replace and reprove the

meter if a meter factor differs from the

previous meter factor by 7 percent or

more.

(l) What are the requirements for tank

facilities designated as a royalty point?

Lessees must:

(1) Equip the tank with a vapor-tight

thief hatch, a vent-line valve, and a fill

line designed to minimize free fall and

splashing;

(2) Submit a complete set of

calibration charts (tank tables) to the

Regional Supervisor before using the

tank for measuring sales;

(3) Obtain the volume and other

measurement parameters by using

correction factors and procedures in the

API MPMS as referenced in 30 CFR

250.1; and

(4) Submit a copy of each run ticket

written from tank gaugings to the

Regional Supervisor within 15 days

after the end of the month.

§ 250.183 Gas measurement

(a) To which meters do MMS

requirements for gas measurement

apply? All OCS gas royalty and

allocation meters.

(b) What are the requirements for

measuring gas? Lessees must:

(1) Commence gas production or make

changes to previously approved

measurement procedures only after the

Regional Supervisor has approved the

gas measurement application or changes

to an existing approval.

(2) Design, install, use, maintain, and

test measurement equipment to ensure

accurate and complete measurement.

You must follow the recommendations

in API MPMS (referenced in 30 CFR

250.1).

(3) Ensure that the measurement

components are compatible with their

connected systems.

(4) Equip the meter with a chart or

electronic data recorder. Electronic data

recorders must be capable of displaying

real-time data during MMS inspections.

(5) Use continuous on-line

chromatographic analyzers or sampling

ports upstream or downstream of the

meter. Take a sample at least once each

calendar month but intervals must not

exceed 42 days.

(6) Ensure that standard conditions

for reporting gross heating value are at

a base temperature of 60° F and at a base

pressure of 14.73 pounds per square

inch absolute (psia).

(7) When requested by the Regional

Supervisor, submit gas volume

statements for each requested month’s

gas sales. Show whether gas volumes

and gross Btu heating value are reported

at saturated or unsaturated conditions.

(8) When requested by the Regional

Supervisor, provide any data necessary

for gas volume and quality calculations.

(c) What are the requirements for gas

meter calibrations? Lessees must:

(1) Calibrate meters monthly but not

exceed 42 days between calibrations.

(2) Following a meter calibration,

adjust the meter equipment (if

necessary) by using the manufacturer’s

specifications.

(3) For positive displacement or

turbine meters, conduct calibrations at

the average hourly rate of flow since the

last calibration.

(4) Retain calibration test data at the

field location for 2 years and send the

data to the Regional Supervisor upon

request.

(5) Permit MMS representatives to

witness regularly scheduled calibrations

and any calibration requested by the

Regional Supervisor.

(d) What must a lessee do if a gas

meter is malfunctioning?

(1) If a gas meter is malfunctioning,

adjust the meter to function properly or

remove it from service and replace it.

(2) Correct the volumes to the last

acceptable calibration as follows:

(i) If the duration of the error can be

determined, calculate the volume

adjustment for that period. The MMS

does not require retroactive volume

adjustments for allocation beyond 21

days; or

(ii) If the duration of the error can’t be

determined, apply the volume

adjustment to one-half of the time

elapsed since the last calibration or 21

days, whichever is less.

(e) What are the requirements when

natural gas from a Federal lease is

delivered to a gas plant?

(1) Lessees must provide the

following to the Regional Supervisor

upon request:

(i) The gas processing plant statement;

(ii) A gas volume statement for each

of the lessee’s meter facility sites that

contribute natural gas to the processing

plant; and

(iii) Composite fractional analyses and

gross heating values.

(2) MMS may inspect the

measurement and sampling equipment

of natural gas processing plants that

process Federal production.

§ 250.184 Surface commingling.

(a) What are the requirements when

commingling production at the surface?

Lessees must:

(1) Commence commingling of

production only after the Regional

Supervisor has approved the

commingling and the method of

measurement.

(2) Submit an application containing

the following information:

(i) The method of allocation

measurement and processing, if

applicable;

(ii) The manner of entry into the

commingled system; and

(iii) Any other information that the

Regional Supervisor requests.

(3) Submit any changes to an

approved commingling application to

the Regional Supervisor for approval.

(4) Upon the request of the Regional

Supervisor, lessees who deliver natural

gas into a commingled system of both

Federal and non-Federal production

must provide volumetric and fractional

analyses on the non-Federal gas through

the designated system operator. If a

lessees fails to provide that data, MMS

will not permit the lessee to deliver

Federal gas into the commingled

system.

(b) What are the requirements for a

well test used for allocation? Lessees

must:
Federal Register / Vol. 62, No. 38 / Wednesday, February 26, 1997 / Proposed Rules 8671

(1) Conduct a well test at least once

every 2 months unless the Regional

Supervisor approved a different

frequency;

(2) Follow the well test procedures in

§ 250.173; and

(3) Retain the well test data at the

field location for 2 years.

§ 250.185 Site Security.

(a) What are the requirements for site

security? Lessees must:

(1) Protect Federal production against

production loss or theft;

(2) Post a sign at each storage tank

that MMS uses to determine royalty.

The sign must contain the name of the

facility operator, the size of the tank,

and the tank number;

(3) Not bypass MMS-approved liquid

hydrocarbon royalty meters and tanks;

and

(4) Report the following to the

Regional Supervisor as soon as possible,

but no later than the next business day

after discovery:

(i) Theft or mishandling of

production;

(ii) Tampering or bypassing of meter

or prover devices; and

(iii) Falsifying production

measurements.

(b) What are the requirements for

using seals? Lessees must:

(1) Seal the following components of

liquid hydrocarbon royalty installations

to ensure that tampering cannot occur

without destroying the seal:

(i) Meter stack component

connections from the base of the stack

to the register;

(ii) Sampling systems including

packing device, fittings, chains, sight

glass, and container lid;

(iii) Temperature and gravity

compensation device components;

(iv) All valves on lines leaving an oil

storage tank including load-out line

valves, drain-line valves, and

connection-line valves between royalty

and non-royalty tanks; and

(v) Any additional components

required by the Regional Supervisor.

(2) Number and track the seals and

keep the record at the field location for

2 years; and

(3) Make the record of seals available

for MMS inspection.

§ 250.186 Measuring gas lost or used on a

lease.

What are the requirements for

measuring gas lost or used on a lease?

(a) Lessees must either measure or

estimate the volume as required by the

Regional Supervisor.

(b) If the Regional Supervisor requires

you to measure the volume, document

the measurement equipment used and

include the volume measured.

(c) If the Regional Supervisor requires

you to estimate the volume, document

the estimating method and the data used

and include the volume estimated.

(d) Lessees must keep the volume

estimates and documentation at the

field location for 2 years.

(e) If the Regional Supervisor

requests, lessees must provide copies of

the records.

[FR Doc. 97–4534 Filed 2–25–97; 8:45 am]

BILLING CODE 4310–MR–M

ENVIRONMENTAL PROTECTION

AGENCY

40 CFR Part 52

[WA50–7123b; FRL–5692–9]

Approval and Promulgation of State

Implementation Plans: Washington

AGENCY: Environmental Protection

Agency (EPA).

ACTION: Proposed rule.

SUMMARY: The Environmental Protection

Agency (EPA) is approving in part, and

disapproving in part, and taking no

action in part on the Regulations of the

Southwest Air Pollution Control

Authority (SWAPCA) for the control of

air pollution in Clark, Cowlitz, Lewis,

Skamania and Wahkiakum Counties,

Washington, as revisions to the

Washington State Implementation Plan

(SIP). These revisions pertain to General

Regulations for Air Pollution Sources

administered by SWAPCA. In the final

rules section of this Federal Register,

the EPA is approving the State’s SIP

revision as a direct final rule without

prior proposal because the Agency

views this as a noncontroversial

revision amendment and anticipates no

adverse comments. A detailed rationale

for the approval is set forth in the direct

final rule. If no adverse comments are

received in response to this proposed

rule, no further activity is contemplated

in relation to this rule. If the EPA

receives adverse comments, the direct

final rule will be withdrawn and all

public comments received will be

addressed in a subsequent final rule

based on this proposed rule. The EPA

will not institute a second comment

period on this action.

DATES: Comments on this proposed rule

must be received in writing by March

28, 1997.

ADDRESSES: Written comments should

be addressed to Montel Livingston,

Environmental Protection Specialist

(OAQ–107), Office of Air Quality, at the

EPA Regional Office listed below.

Copies of the documents relevant to this

proposed rule are available for public

inspection during normal business

hours at the following locations. The

interested persons wanting to examine

these documents should make an

appointment with the appropriate office

at least 24 hours before the visiting day.

Environmental Protection Agency,

Region 10, Office of Air Quality, 1200

6th Avenue, Seattle, WA 98101.

Washington State Department of

Ecology, P.O. Box 47600, PV–11,

Olympia, WA, 98504–7600.

FOR FURTHER INFORMATION CONTACT:

Wayne Elson, Office of Air Quality

(OAQ–107), EPA, 1200 6th Avenue,

Seattle, WA 98101, (206) 553–1463.

SUPPLEMENTARY INFORMATION: See the

information provided in the Direct Final

action which is located in the rules

section of this Federal Register.

Dated: February 14, 1997.

Charles Findley,

Acting Regional Administrator.

[FR Doc. 97–4660 Filed 2–25–97; 8:45 am]

BILLING CODE 6560–50–P

FEDERAL COMMUNICATIONS

COMMISSION

47 CFR Parts 52 and 64

[CC Docket No. 92–105; FCC 97–51]

The Use of N11 Codes and Other

Abbreviated Dialing Arrangements

AGENCY: Federal Communications

Commission.

ACTION: Proposed Rule.

SUMMARY: On February 19, 1997, the

Commission released a Further Notice

of Proposed Rulemaking (FNPRM)

addressing N11 codes. The FNPRM is

intended to obtain comment on the

technical feasibility of implementing

711 for access to telecommunications

relay services (TRS) and on several

other issues related to N11 code

administration.

DATES: Comments must be filed on or

before March 31, 1997, and reply

comments must be filed on or before

April 30, 1997.

ADDRESSES: Federal Communications

Commission, 1919 M Street, N.W.,

Washington, DC 20554.

FOR FURTHER INFORMATION CONTACT:

Elizabeth Nightingale, Attorney,

Network Services Division, Common

Carrier Bureau, (202) 418–2352.

SUPPLEMENTARY INFORMATION: This

summarizes the Commission’s Further

Notice of Proposed Rulemaking in the

matter of The Use of N11 Codes and

Other Abbreviated Dialing