26362 Federal Register / Vol. 63, No. 91 /Tuesday, May 12, 1998 /Rules and Regulations

DEPARTMENT OF THE INTERIOR

Minerals Management Service

30 CFR Parts 202, 216, and 250

RIN 1010–AC23

Royalties on Gas, Gas Analysis

Reports, Oil and Gas Production

Measurement, Surface Commingling,

and Security

AGENCY: Minerals Management Service

(MMS), Interior.

ACTION: Final rule.

SUMMARY: This final rule amends MMS’s

regulations governing oil and gas

operations in the Outer Continental

Shelf (OCS) to update production

measurement, surface commingling, and

security requirements. It also amends

the standards for reporting and paying

royalties on gas. MMS needs this rule to

implement a system to verify that gas

sales are reported accurately.

EFFECTIVE DATES: July 13, 1998. The

incorporation by reference of certain

publications listed in the regulations is

approved by the Director of the Federal

Register as of July 13, 1998.

FOR FURTHER INFORMATION CONTACT:

Sharon Buffington, Engineering and

Research Branch, at (703) 787–1147.

SUPPLEMENTARY INFORMATION: On

February 26, 1997, MMS published the

proposed rule for 30 CFR part 250,

Subpart L in the Federal Register (62 FR

8665). During the 90-day comment

period that ended on May 27, 1997,

MMS received comments from five

organizations.

Similarly, on April 4, 1997, MMS

published the proposed rule for 30 CFR

parts 202 and 216 (62 FR 16121). During

the 30-day comment period that ended

on May 5, 1997, MMS did not receive

any formal comments. This final rule

combines both of these proposed rules.

We have combined RIN numbers 1010–

AB97 and 1010–AC23 and we are now

using the most recent RIN 1010–AC23

for this rule. The rule is necessary to:

• Reflect current industry technology,

• Form the basis for a gas verification

system (GVS), and

• Require tracking of gas lost or used

on the lease.

The Response to Comments section

discusses the comments that MMS

received from the proposed rule on oil

and gas production measurement,

surface commingling, and security. We

appreciate the suggestions and

comments that we received.

Response to Comments

Section 250.181 Definitions

MMS received comments to revise the

following definitions to make them

clearer or to align them with industry

use and standards. In many cases, we

agreed and made the appropriate

changes to the definition.

• Allocation meter—We revised the

definition to make it clearer, but we did

not align it with the standard industry

definition because the term carries a

different meaning for purposes of this

subpart.

• British Thermal Unit (Btu)—We

revised the definition to align it with

text book use, but we did not add a

requirement to use Gas Processors

Association (GPA) standards to

calculate the ideal heating value at this

time. We are further analyzing the GPA

standards.

• Calibration—We revised the

definition for clarity. We also added a

phrase to show that, in this subpart,

calibration includes testing (verifying)

and correcting (if necessary) a

measuring device.

• Fractional analysis—We changed

‘‘fractional’’ to ‘‘compositional’’ analysis

for clarity. However, we rejected the

recommendation in the comments to

state that it is always on a gas analysis

report, because the compositional

analyses may not be on that report.

• Gas lost—One commenter

suggested that we define this term. We

agree, and have added it to the final

rule. Gas lost is gas that is neither sold

nor used on the lease or unit nor used

internally by the producer.

• Gas allocation meter—We deleted

the definition because it is covered

under the definition of allocation meter.

• Gas meter—We received a comment

suggesting that we delete the term gas

meter because it is not necessary. We

agree and deleted it accordingly.

• Gas processing plant and gas

processing plant statement—We revised

the definitions for clarity. We received

a comment to the effect that the inlet

stream is not always measured for

volume and quality and that the

statement may be a large document. We

will work with industry to get the

information that we need in the most

convenient format. Also, we do not

expect to need more than a few gas

processing plant statements per year.

We are accounting for the cost in the

information collection report.

• Gas royalty meter malfunction—We

revised the definition for clarity.

• Gas volume statement—We revised

the definition for clarity. We agree with

comments to the effect that the owner of

the meter is not always the transporter

of the gas. We therefore eliminated the

descriptive statement that the owner of

the gas meter prepares the document.

• Inventory tank—We added the

definition for inventory tank because we

use it in this subpart.

• Liquid hydrocarbon—We revised

the definition for clarity. Contrary to the

suggestion of one commenter, we did

not define liquid hydrocarbons as

hydrocarbons that always pass through

lease facilities, because the processing

plants are sometimes located onshore

and not on an OCS lease.

• Natural gas—We revised the

definition of natural gas for clarity.

• Operating meter—We revised the

definition to clarify that the term

includes only royalty and allocation

meters.

• Pressure base and temperature

base—We revised the definitions to

require that these bases be used for

reporting quality as well as volume.

• Prove—We revised the definition to

agree with industry standards.

• Retrograde condensate—We revised

the definition to agree with industry

standards and added the term

‘‘pipeline’’ condensate here and

throughout this subpart.

• Royalty meter—We revised the

definition for clarity and accuracy.

• Royalty tank—We added this

definition because it was cited under

§ 250.182(l) and not previously defined.

• You or your—We changed the word

‘‘contractor’’ in this definition to

‘‘lessees’ representative’’ because much

of the work in this subpart is performed

by the lessees’ representative.

Section 250.182 Liquid Hydrocarbon

Measurement

• (b)(1)(i)—We received a comment to

add turbine meters in addition to the

positive displacement meters referenced

in the proposed rule. We also received

a comment that coriolis meters might be

used. We agree. We have therefore made

more general requirements.

• (b)(1)(v)—We added that a sediment

and water monitor must be located

upstream of the divert valve to recognize

this common industry practice.

• (b)(4)(i)—We received a comment

suggesting that we reference the

industry standards for sampling. We

agree and we revised the language

accordingly.

• (b)(4)(iii)—We received a comment

to be more specific about the sample

probe location. We agree and made the

suggested changes.

• (c)—We distinguished the

requirements for run tickets that result

from royalty meters from the

requirements for run tickets pertaining

to royalty tanks because they should be
Federal Register / Vol. 63, No. 91 /Tuesday, May 12, 1998 /Rules and Regulations 26363

treated slightly differently. We also

reorganized this paragraph in order of

importance.

• (d)(4)—We added a statement that

allows for provings on a schedule that

is different than monthly if the Regional

Supervisor approves. This allows for

unique situations that may occur.

• (e)(1)—We received a suggestion to

require that the master meter be proved

at several different rates to allow for the

development of a meter factor curve. We

realize that industry sometimes does

this, and we will continue to evaluate

this suggestion. We may address this, as

well as technology advances, in a future

rulemaking on gas measurement after

the GVS is implemented.

• (h)(1)—We received a comment to

change this phrase to the passive voice.

MMS did not adopt this

recommendation because we are trying

to write in the active voice to clarify

who must meet the requirement. We

also received a comment to list the

decimal value and the percentage for the

differences in proof runs. We did not

adopt this recommendation throughout

because, in some cases, the output is an

absolute number and in other cases the

calculation leads to a percentage. We

therefore, kept them separate.

• (h)(2)—We received a comment to

change the language on the master meter

proof runs to conform with industry

standards. We have adopted the

recommendation.

• (i)(1)(i)—We received a comment to

add the term ‘‘inspect’’ before adjusting

a meter to conform with industry

standards. We agree, and we revised the

language.

• (i)(2)(iii)—We changed the location

of reporting unregistered production

from the proving report to the run ticket

because this is standard practice.

• (k)(1)—We agree with a comment to

add the modifier ‘‘proportional to flow’’

to clarify the meaning of taking a sample

continuously. Therefore, we revised the

language.

• (k)(6)—We received a comment that

adjusting and reproving the meter (if a

meter factor differs from a previous

meter factor by a specified percentage)

is an accounting adjustment and not a

physical one. The comment is not

accurate. This provision refers to a

physical adjustment of the meter.

• (k)(7) and (k)(8)—We received a

comment to combine these statements.

We have not combined them because

another commenter recommended that

we recognize that turbine meters cannot

be adjusted. Combining the statements

would not properly list the

requirements for turbine meters. Also,

paragraph (k)(8) discusses the required

procedure when the meter factor differs

by seven percent or more, in contrast to

paragraph (k)(7)’s applicability to a

meter factor difference of between two

and seven percent. However, we have

clarified the language to more precisely

delineate the differences.

• (k)(9)—We added clarification that

MMS may witness allocation meter

provings. While this is not a change in

policy, there seemed to be some

question in the comments regarding

whether MMS may witness allocation

meter provings in addition to royalty

meter provings.

• (l)—We separated tank facilities

into ‘‘royalty’’ and ‘‘inventory’’ tank

facilities because they should be treated

differently.

Section 250.183 Gas Measurement

• (b)—We received a comment

recommending that we include

‘‘operators’’ with ‘‘lessees’’ as parties

who must meet this section’s

requirements. We agree. However, since

the term ‘‘ you’’ or ‘‘your’’ expressly

includes operators and other lessee’s

representatives, this objective is

accomplished by using the term ‘‘you,’’

which we have done throughout the

final rule.

• (b)(2)—We received a comment to

add the term ‘‘verifiable’’ instead of the

word ‘‘complete’’ before

‘‘measurement.’’ We agree, and we

modified the language.

• (b)(3)—We received a comment to

add the phrase that measurement

components ‘‘should demonstrate

consistent levels of accuracy throughout

the system’’ instead of ‘‘compatible with

their connected systems.’’ We added the

phrase with the exception of the

‘‘should.’’ MMS regulations are

replacing forms of ‘‘shall’’ with ‘‘must.’’

• (b)(4)—We received comments

saying that real time data should be

displayed at the flow computer only.

We agree, and we eliminated the phrase

in the second sentence and referenced

the industry standards.

• (b)(5)—We received comments

saying that using on-line

chromatographic analyzers is not

necessary and not an industry practice

because spot samples are sometimes

taken. We agree, and we modified the

language to reflect this. However, we

did not restrict it to royalty sales meters

because, like the current requirements

on gas measurement, this also applies to

allocation meters. However, less than 10

percent of the approved meters are

allocation meters. Also, because MMS

does not want to burden industry with

additional sampling requirements, we

changed the requirement from

‘‘monthly’’ to at least ‘‘every 6 months’’

to correspond with current industry

practice.

• (b)(6)—MMS may need to see the

gas quality information gathered from

sampling; therefore, we added a

reporting requirement on gas sampling

information that is already available to

the lessee. However, we anticipate that

we will only occasionally request the

information.

• (b)(7)—We added that the standard

conditions for reporting gross heating

value reflect the same degree of water

saturation as in the gas volume to agree

with Royalty Management regulations.

We understand that this is standard

industry practice.

• (b)(8)—We received a comment that

we need to clarify that we will accept

copies of the gas volume statements. We

agree, and we made this change. We

also received a comment that it is

unclear as to how and when the

statements will be requested, and if this

is a limited sampling program. The

Regional Supervisor will request, from

the lessee or the lessees’ representative,

a sampling of the statements, at various

times during the year, covering the

previous month. We expect the

emphasis to be on OCS gas royalty

meters.

• (b)(9)—We received comments

saying that the data that the Regional

Supervisor may request in this

requirement is too open ended. We

agree, and we modified the language

accordingly. We recognize that

occasionally the data that we need

concerning volume and quality

dispositions may not be on the gas

volume statement; therefore, this

requirement is meant to encompass that

data. We also modified the Information

Collection Request to reflect that, at

first, this data may take longer to

retrieve than we originally estimated.

However, we feel that this will become

routine after the first few submittals.

• (c)(1)—We received a comment

saying that we should not change the

current rates for calibrations. However,

a monthly calibration is needed to

ensure that the meters stay accurate, so

we have not made the recommended

change.

• (c)(2)—We received a comment

saying that we should add ‘‘test (verify),

repair, or/and calibrate the meter.’’ We

agree that these are the steps; however,

our definition of calibration includes

these steps so we changed the language

to say ‘‘calibrate each meter by using the

manufacturer’s specifications.’’

• (c)(3)—We deleted the reference to

specific meter types because other

meters may be used. We also recognize

that, as the commenter said, gas turbine

meters are not customarily calibrated
26364 Federal Register / Vol. 63, No. 91 /Tuesday, May 12, 1998 /Rules and Regulations

but are subject to operational testing. In

addition, we added that the calibration

should be as close as possible to the

average hourly rate because we received

a comment that the flow rate may be

beyond the control of those responsible

for calibration. We also received a

comment that a meter factor curve

should be allowed because it will

increase accuracy. We are still

evaluating this comment and we will

analyze it for use in future rulemakings.

• (c)(4)—We received a comment that

we should delete the term ‘‘test data.’’

We agree, and we changed the language

to require that calibration reports, rather

than test data, be retained.

• (c)(5)—We received a comment that

MMS should witness only OCS royalty

meter calibrations so we should change

the rule to reflect this. We disagree.

MMS may witness any calibrations for

OCS royalty or allocation meters as

defined in this subpart. In fact, the

requirements in § 250.183 apply to both

OCS gas royalty and allocation meters.

This is not a change from the current

requirements or the current policy.

However, less than 10 percent of the

approved meters are allocation meters.

Inspections are needed if royalty is

affected.

• (d)—We received a comment to add

‘‘out of calibration or’’ before

‘‘malfunctioning’’ because orifice meters

are referred to as ‘‘out of calibration.’’

We agree, and we made the change. We

also received a comment that a meter

malfunction is when it is not operating

within contractual tolerances. We agree,

and we revised the language and the

definition.

• (d)(1)—We received a comment that

the requirement to calibrate gas meters

should only refer to royalty meters. We

disagree. Gas allocation meters must

also be calibrated. This is not a change

from current requirements.

• (d)(2)(i)—One commenter

recommended removing the statement

that MMS ‘‘does not require retroactive

volume adjustments for allocation

beyond 21 days’’ that was made in the

proposed rule after the requirement to

calculate the volume adjustment for the

determinable period of a calibration

error. The commenter felt that the

quoted statement would hinder industry

in obtaining monetary adjustments from

purchasers for periods longer than 21

days for which adjustments for

allocation would be nevertheless

required because the error period could

not be determined. We agree, and we

revised the final rule accordingly.

• (e)(1)(i)—We received a comment to

add that we are requiring only a copy

of the gas processing plant statement.

We agree, and we revised the final rule.

We also received a comment to be more

specific about what we are asking for on

the statement. We agree, and the new

paragraph (e)(1)(ii), specifies that we

need the gross heating values of the

inlet and residue streams if they are not

reported on the gas plant statement.

However, we believe that most gas plant

statements will have the necessary

information.

• (e)(1)(ii)—We received a comment

saying that we should delete the

requirement to submit gas volume

statements for each meter facility

because the information will already be

on the gas volume statement that we

may request. We agree, and we deleted

the requirement.

• (e)(1)(iii)—We received a comment

saying that gathering the compositional

fractional analyses for the gas plant

statements will be very time consuming

for industry. We agree, and we deleted

the term ‘‘composite fractional

analyses.’’

• (e)(2)—One commenter inquired

why MMS would inspect gas plants.

MMS recognizes that most of the royalty

measuring points for gas meters in the

Gulf of Mexico OCS are located on OCS

offshore facilities. However, that is not

the case in the Pacific OCS where

almost all of the oil and gas royalty

measuring points are located at an

onshore oil and gas plant facility and

operated by the lessee.

Though most onshore oil and gas

plants are on State owned property, the

oil and gas that comes into the plant is

still oil and gas produced from the

Federal OCS and subject to all of the

laws and regulations pertaining to

Federal royalty and inspection

requirements. This includes access to

the onshore facility’s Liquid Automatic

Custody Transfer (LACT) Unit and gas

sales meters for the purpose of

witnessing a LACT meter proving, a gas

meter calibration, or site security for

both royalty measuring points. These

inspections will continue to be

conducted by MMS inspectors.

However, we only expect to need

information from a relatively few gas

plants each year.

Section 250.184 Surface Commingling

• (a)(2)(iii)—We received a comment

saying that this requirement was too

open ended as stated. We agree. In the

end, we deleted most of the specific

requirements concerning the contents of

a commingling application because we

did not want to create a

misunderstanding that no other kinds of

information would ever be necessary.

Because each commingling application

is unique, it is best to contact the

Regional Supervisor prior to submitting

a commingling application.

• (a)(3)—We received a comment

saying that MMS should publish the

paper presented at the May 29, 1996,

Acadian Flow Measurement Society

Conference. Because it is only an

example of a commingling application,

we have not published it as part of the

regulations. However, the paper is

available to the public. Please contact

the Regional Supervisor in the Gulf of

Mexico OCS Region if you would like a

copy.

• (a)(4)—We received a comment that

MMS should delete this requirement

[currently (a)(2)] because it is

inappropriate. We agree that as written

it may be confusing; therefore, we

significantly re-wrote the requirement

for clarity.

Section 250.185 Site Security

• (a)(2)—We received a request to

clarify if this requirement pertains to

onshore or offshore tanks and to stock

or surge tanks. This applies to both

inventory and royalty tanks (onshore

and offshore) which are used in the

royalty determination process.

Therefore, by definition, this includes

surge tanks. We clarified the

requirement.

• (b)(1)—We received a comment to

add the term ‘‘meter’’ after ‘‘royalty.’’

We agree, and we revised the final rule

for clarification.

• (b)(1)(i)—We received a comment

saying that it is impractical to seal the

conduit leading to the control room. We

agree, and we modified the language to

clarify the location for the seals.

• (b)(1)(ii)—We received a comment

requesting clarification on the seals for

sampling systems. We agree, and we

removed the term chains.

• (b)(2)—We received comments

concerning our statement in the

preamble that we may require seals on

gas meters. A comment stated that it is

impractical to seal an orifice meter.

Another comment said that to seal all

valves and gas metering devices in the

Gulf of Mexico is needless. We did not

intend to have orifice meter, or all

valves and gas meter devices, sealed.

Therefore, we changed the language to

say seal all bypass valves of gas royalty

and allocation meters. We are including

the increased cost of the seals in our

economic analysis.

Section 250.186 Measuring Gas Lost or

Used on a Lease

In the final rule, MMS moved this

section to new paragraphs in

§ 250.183 (f) (1) through (5) because it

relates to gas measurement.
Federal Register / Vol. 63, No. 91 /Tuesday, May 12, 1998 /Rules and Regulations 26365

• (a)—We received comments that

MMS should not require a lessee to

measure the gas lost or used on a lease

in every case because we currently

allow them to either estimate or

measure those volumes. We agree, and

we modified the language.

• (b)—We received a comment that

the cost of measuring gas lost or used on

a lease would be substantial if the

meters are not currently in place. We

agree, and we modified the language to

give the lessee the option of measuring

or estimating the gas lost or used. We

also received a question concerning

what we mean by gas lost. Gas lost is gas

that is neither sold nor used on the lease

or unit nor used internally by the

producer. We have added a definition of

this term in § 250.181.

• (d)—We received a comment that

documents are not always retained at

the site but they can be easily obtained

for an inspector to see. We agree, and

we modified the language in the final

rule. We also added that the documents

must be kept for at least 2 years for

consistency with audit requirements. If

an audit occurs, MMS requires 6 years

of documents under separate regulations

governing audits. However, the

inspectors will only need to see

documents for the previous 2 years.

General Comments

• We received comments concerning

the time it will take to submit copies of

gas volume statements. We intend for

this to be a sampling approach—on an

‘‘as needed’’ basis, upon the request of

the Regional Supervisor. We realize that

at first it will take longer to submit the

copies of the statements. Also,

occasionally we anticipate that the

statement may not have the usual and

customary volume and quality

information or the saturation

conditions. However, in time, the

needed information should become

relatively routine to obtain. We will

work with industry to minimize the

burden and to make the reporting and

the methods of reporting as

accommodating as possible. We also

modified the information collection to

reflect the possibility of some

information being more difficult to

obtain at first.

• We received comments on the

subject of ‘‘Documents Incorporated.’’

The comment said that we need to

incorporate three additional Chapters

from the American Petroleum Institute

(API) Manual of Petroleum

Measurement Standard (MPMS). After

reviewing the Chapters, we have

incorporated: Chapter 1, Vocabulary;

Chapter 20.1, Allocation Measurement;

and Chapter 21.1, Electronic Gas

Measurement as referenced in 30 CFR

250, Subpart A. MMS regulations that

are different than the cited standards

supercede the standard. For example,

MMS has a few slightly different

definitions and a different calibration

rate than the cited standard, but MMS

requirements will supercede the

standard. Further, by adopting the API

MPMS Chapter 20.1, Allocation

Measurement, MMS is not automatically

adopting the API MPMS Chapter 14.1,

Collecting and Handling of Natural Gas

Samples for Custody Transfer, which is

cited in the standard document. We are

reviewing that standard. Also, the new

tabular format for the documents that

we incorporate was created to assist

users to easily find the citations for the

documents that we incorporate by

reference. We hope that you find this

useful.

• In the proposed rule, MMS also

sought comments on the applicable

industry standards listed in 30 CFR

250.1 and incorporated by reference in

the proposed rule (62 FR 8666). MMS

received no negative comments on the

use of those standards.

Executive Order (E.O.) 12866

This rule is not significant under E.O.

12866 and has not been reviewed by the

Office of Management and Budget. The

estimated total annual cost of

compliance is less than $100 million,

and the estimated level of newly

imposed costs should not affect

business and operating decisions in the

OCS.

E.O. 12988

The Department of the Interior (DOI)

has certified to the Office of

Management and Budget (OMB) that

this 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

DOI has determined that because this

rule applies to all OCS lessees, the

lessees that are small businesses will be

affected. However, the new economic

burden, that includes collecting

information and keeping records, is not

a significant burden when compared to

the amount of funding that is required

to operate in the OCS. The annual

burden to all OCS lessees is expected to

be $186,550 for reporting and

recordkeeping. In addition, the annual

burden for complying with new seal and

sampling requirements that are not

standard practice is estimated to be

$21,000. The impact is calculated using

$35 per burden hour. In comparison, the

average annual operating cost for each

facility on the OCS is approximately $1

million per facility and $300,000 per

well. This is in addition to the capital

cost for the facility which may be

greater than $200 million. Your

comments are important. The Small

Business and Agriculture Regulatory

Enforcement Ombudsman and 10

Regional Fairness Boards were

established to receive comments from

small business 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 enforcement

actions of MMS, call toll-free (888) 734–

3247.

Paperwork Reduction Act (PRA)

This rule contains information

collections with different OMB approval

numbers. The information collections

are affected by this rule as shown in the

following table.

The information collections in

Have the OMB

approval numberand

Parts 202 and 216 ................................................................................................................... 1010–0040 Are not modified by this rule.

Subpart L of part 250 ............................................................................................................... 1010–0051 Are modified by this rule.

As part of the notice of proposed

rulemaking (NPR) process, we

submitted the revised information collection requirements in 30 CFR part

250, Subpart L, to OMB for approval.
26366 Federal Register / Vol. 63, No. 91 /Tuesday, May 12, 1998 /Rules and Regulations

OMB approved the information

collection under OMB Control No. 1010-

0051. A discussion of the comments

received on the information collection

aspects of the NPR for this subpart is

included in the preamble. Based on

changes made in this rule, we’ve

submitted a revised information

collection package to OMB for approval.

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.

The information collection aspects of

this final rule will not take effect until

approved by OMB. We will publish a

notice in the Federal Register

announcing the OMB approval of the

revised collection of information

associated with 30 CFR 250, Subpart L.

We invite the public and other

Federal agencies to comment on this

collection of information. Send

comments regarding any aspect of the

collection to the Office of Information

and Regulatory Affairs, OMB, Attention:

Desk Officer for the Interior Department

(1010–0051), 725 17th Street N.W.,

Washington, D.C. 20503. Send a copy of

your comments to the Information

Collection Clearance Officer, Minerals

Management Service, 1849 C Street

N.W., MS 4230, Washington, D.C.

20240. OMB is required to make a

decision concerning the collection of

information contained in this final rule

between 30 and 60 days after

publication of this document in the

Federal Register. Therefore, your

comments are best assured of being

considered by OMB if OMB receives

them by June 11, 1998.

This final rule for 30 CFR part 250,

Subpart L, makes very few changes to

the information collection requirements

approved for the proposed rulemaking.

Minor changes include relocating or

separating various requirements for

clarity and specificity. We reestimated

the burdens for providing gas volume

statements to reflect that, at first, these

data may take longer to retrieve than we

originally estimated. We also made

slight adjustments to other estimates.

There are two new requirements at

§§ 250.182(a)(4) and (d)(4). The first

requires lessees to submit pipeline

(retrograde) condensate volumes upon

request; and the second accommodates

unique situations that may occur and

allows for provings on a schedule that

is different than monthly if the Regional

Supervisor approves.

MMS collects the information

required in Subpart L in order to ensure

that the volumes of hydrocarbons

produced are measured accurately, and

royalties are paid on the proper

volumes. Specifically, MMS uses the

information to:

• Determine if measurement

equipment is properly installed,

provides accurate measurement of

production on which royalty is due, and

is operating properly;

• Obtain rates of production data in

allocating the volumes of production

measured at royalty sales meters which

can be examined during field

inspections;

• Ascertain if all removals of oil and

condensate from the lease are reported;

• Determine the amount of oil that

was shipped when measurements are

taken by gauging the tanks rather than

being measured by a meter;

• Ensure that the sales location is

secure and production cannot be

removed without the volumes being

recorded; and

• Review proving reports to verify

that data on run tickets are calculated

and reported accurately.

Responses are mandatory. We will

protect information considered

proprietary under applicable law and

under regulations at § 250.18 of this part

and 30 CFR part 252 of this chapter.

Respondents are approximately 130

Federal OCS oil and gas lessees. The

reporting and recordkeeping hour

burden varies by section of the rule. We

estimate the total burden will average

approximately 41 hours per respondent.

This includes the time for reviewing

instructions, searching existing data

sources, gathering and maintaining the

data needed, and completing and

reviewing the collection of information.

You may contact the MMS Information

Collection Clearance Officer at 202/208–

7744 to obtain a copy of the burden

breakdown and the complete supporting

statement submitted to OMB. In

calculating the burdens, we’ve assumed

that respondents perform some of the

requirements and maintain records in

the normal course of their activities. We

consider these to be usual and

customary. We invite your comments if

you disagree with this assumption.

(1) We specifically solicit comments

on the following questions:

(a) Is the proposed collection of

information necessary for us to properly

perform our functions, and will it be

useful?

(b) Are the burden hour estimates

reasonable for the proposed collection?

(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 the

applicants, including the use of

appropriate automated electronic,

mechanical, or other forms of

information technology?

(2) In addition, the PRA requires us to

estimate the total annual cost burden to

respondents or recordkeepers resulting

from the collection of information. We

need your comments on this item. Your

response should split the cost estimate

into two components:

(a) Total capital and startup cost

component; and

(b) Annual operation, maintenance,

and purchase of services component.

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: (i) before October 1, 1995;

(ii) to comply with requirements not

associated with the information

collection; (iii) for reasons other than to

provide information or keep records for

the Government; or (iv) as part of

customary and usual business or private

practices.

Takings Implication Assessment

DOI certifies that this 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,

Governmental Actions and Interference

with Constitutionally Protected Property

Rights.

National Environmental Policy Act

DOI determined that this rule does

not constitute a major Federal action

significantly affecting the quality of the

human environment; therefore, an

Environmental Impact Statement is not

required.

List of Subjects

30 CFR Part 202

Coal, Continental shelf, Geothermal

energy, Government contracts, Indian

lands, Mineral royalties, Natural gas,

Petroleum, Public lands-mineral

resources, Reporting and recordkeeping

requirements.
Federal Register / Vol. 63, No. 91 /Tuesday, May 12, 1998 /Rules and Regulations 26367

30 CFR Part 216

Coal, Continental shelf, Geothermal

energy, Government contracts, Indian

lands, Mineral royalties, Natural gas,

Penalties, Petroleum, Public landsmineral resources, Reporting and

recordkeeping requirements.

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: April 24, 1998.

Bob Armstrong,

Assistant Secretary, Land and Minerals

Management.

For the reasons stated in the

preamble, the Minerals Management

Service (MMS) is amending 30 CFR

parts 202, 216, and 250 as follows:

PART 202—ROYALTIES

1. The authority citation for part 202

continues to read as follows:

Authority: 5 U.S.C. 301 et seq., 25 U.S.C.

396 et seq., 396a et seq., 2101 et seq., 30

U.S.C. 181 et seq., 351 et seq., 1001 et seq.,

1701 et seq., 31 U.S.C. 9701 et seq., 43 U.S.C.

1301 et seq., 1331 et seq., 1801 et seq.

Subpart D—Federal and Indian Gas

2. Revise § 202.152(a)(1) to read as

follows:

§ 202.152 Standards for reporting and

paying royalties on gas.

(a)(1) If you are responsible for

reporting production or royalties, you

must:

(i) Report gas volumes and British

thermal unit (Btu) heating values, if

applicable, under the same degree of

water saturation;

(ii) Report gas volumes in units of

1,000 cubic feet (mcf); and

(iii) Report gas volumes and Btu

heating value at a standard pressure

base of 14.73 pounds per square inch

absolute (psia) and a standard

temperature base of 60° F.

* * * * *

PART 216—PRODUCTION

ACCOUNTING

1. The authority citation for part 216

continues to read as follows:

Authority: 5 U.S.C. 301 et seq., 25 U.S.C.

396 et seq., 396a et seq., 2101 et seq., 30

U.S.C. 181 et seq., 351 et seq., 1001 et seq.,

1701 et seq., 31 U.S.C. 3716, 3720A, 9701, 43

U.S.C. 1301 et seq., 1331 et seq., 1801 et seq.

Subpart B—Oil and Gas, General

2. Revise § 216.54 to read as follows:

§ 216.54 Gas Analysis Report.

When requested by MMS, any

operator must file a Gas Analysis Report

(GAR) (Form MMS–4055) for each

royalty or allocation meter. The form

must contain accurate and detailed gas

analysis information. This requirement

applies to offshore, onshore, or Indian

leases.

(a) MMS may request a GAR when

you sell gas, or transfer gas for

processing, before the point of royalty

computation.

(b) When MMS first requests this

report, the report is due within 30 days.

If MMS requests subsequent reports,

they will be due no later than 45 days

after the end of the month covered by

the report.

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.

2. Revise § 250.1 to read as follows:

§ 250.1 Documents incorporated by

reference.

(a) MMS is incorporating by reference

the documents listed in the table in

paragraph (d) of this section. The

Director of the Federal Register has

approved this incorporation by

reference in accordance with 5 U.S.C.

552(a) and 1 CFR part 51.

(1) MMS will publish any changes to

these documents in the Federal

Register.

(2) The rule change will become

effective without prior opportunity to

comment when MMS determines that

the revisions to a document result in

safety improvements or represent new

industry standard technology, and do

not impose undue costs on the affected

parties.

(b) MMS has incorporated each

document or specific portion by

reference in the sections noted. The

entire document is incorporated by

reference, unless the text of the

corresponding sections in this part calls

for compliance with specific portions of

the listed documents. In each instance,

the applicable document is the specific

edition or specific edition and

supplement or addendum cited in this

section.

(c) In accordance with §§ 250.3 (c),

and 250.14(b), you may comply with a

later edition of a specific document

incorporated by reference provided:

(1) You demonstrate that compliance

with the later edition provides a degree

of protection, safety, or performance

equal to or better than that which would

be achieved by compliance with the

listed edition; and

(2) You obtain the prior written

approval for alternative compliance

from the authorized MMS official.

(d) You may inspect these documents

at the Minerals Management Service,

381 Elden Street, Room 3313, Herndon,

Virginia; or at the Office of the Federal

Register, 800 North Capitol Street, N.W.,

Suite 700, Washington, D.C.. You may

obtain the documents from the

publishing organizations at the

addresses given in the following table.

For Write to

ACI Standards ..................................................... American Concrete Institute, P. O. Box 19150, Detroit, MI 48219.

AISC Standards .................................................. AISC—American Institute of Steel Construction, Inc., P.O. Box 4588, Chicago, IL 60680.

ANSI/ASME Codes ............................................. American National Standards Institute, Attention Sales Department, 1430 Broadway, New

York, NY 10018; and/or American Society of Mechanical Engineers, United Engineering

Center, 345 East 47th Street, New York, NY 10017.

API Recommended Practices, Specs, Standards, Manual of Petroleum Measurement

Standards (MPMS) chapters.

American Petroleum Institute, 1220 L Street N.W., Washington, D.C. 20005.

ASTM Standards ................................................. American Society for Testing and Materials, 1916 Race Street, Philadelphia, PA 19103.

AWS Codes ........................................................ American Welding Society, 550 N.W., LeJeune Road, P.O. Box 351040, Miami, FL 33135.

NACE Standards ................................................. National Association of Corrosion Engineers, P.O. Box 218340, Houston, TX 77218.
26368 Federal Register / Vol. 63, No. 91 /Tuesday, May 12, 1998 /Rules and Regulations

(e) In order to easily reference text of the corresponding sections with the list of documents incorporated by reference,

the list is in alphanumerical order by organization and document.

Title of document Incorporated by reference at

ACI Standard 318–95, Building Code Requirements for Reinforced Concrete, plus Commentary

on Building Code Requirements for Reinforced Concrete (ACI 318R–95).

§ 250.138(b)(4)(i), (b)(6)(i), (b)(7), (b)(8)(i),

(b)(9), (b)(10), (c)(3), (d)(1)(v), (d)(5), (d)(6),

(d)(7), (d)(8), (d)(9), (e)(1)(i), (e)(2)(i).

ACI Standard 357–R–84, Guide for the Design and Construction of Fixed Offshore Concrete

Structures, 1984.

§ 250.130(g);§ 250.138 (c)(2), (c)(3).

AISC Standard, Specification for Structural Steel for Buildings, Allowable Stress Design and

Plastic Design, June 1, 1989, with Commentary.

§ 250.137(b)(1)(ii), (c)(4)(ii), (c)(4)(vii).

ANSI/ASME Boiler and Pressure Vessel Code, Section I, Power Boilers including Appendices,

1995 Edition.

§ 250.123(b)(1), (b)(1)(i); § 250.292(b)(1),

(b)(1)(i).

ANSI/ASME Boiler and Pressure Vessel Code, Section IV, Heating Boilers including Nonmandatory Appendices A, B, C, D, E, F, H, I, and J, and the Guide to Manufacturers Data

Report Forms, 1995 Edition.

§ 250.123(b)(1), (b)(1)(i); § 250.292(b)(1),

(b)(1)(i).

ANSI/ASME Boiler and Pressure Vessel Code, Section VIII, Pressure Vessels, Divisions 1 and

2, including Nonmandatory Appendices, 1995 Edition.

§ 250.123(b)(1), (b)(1)(i); § 250.292(b)(1),

(b)(1)(i).

ANSI/ASME B 16.5–1988 (including Errata) and B 16.5a–1992 Addenda, Pipe Flanges and

Flanged Fittings.

§ 250.152(b)(2).

ANSI/ASME B 31.8–1995, Gas Transmission and Distribution Piping Systems ........................... § 250.152(a).

ANSI Z88.2—1992, American National Standard for Respiratory Protection ................................ § 250.67(g)(4)(iv), (j)(13)(ii).

ANSI/ASME SPPE–1–1994 and SPPE–1d–1996, ADDENDA, Quality Assurance and Certification of Safety and Pollution Prevention Equipment Used in Offshore Oil and Gas Operations.§ 250.126(a)(2)(ii).

API RP 2A, Recommended Practice for Planning, Designing and Constructing Fixed Offshore

Platforms Working Stress Design, Nineteenth Edition, August 1, 1991, API Stock No. 811–

00200.

§ 250.130(g); § 250.142(a).

API RP 2D, Recommended Practice for Operation and Maintenance of Offshore Cranes, Third

Edition, June 1, 1995, API Stock No. G02D03.

§ 250.20(c); § 250.260(g).

API RP 14B, Recommended Practice for Design, Installation, Repair and Operation of Subsurface Safety Valve Systems, Fourth Edition, July 1, 1994, with Errata dated June 1996,

API Stock No. G14B04.

§ 250.121(e)(4); § 250.124(a)(1)(i);

§ 250.126(d).

API RP 14C, Recommended Practice for Analysis, Design, Installation and Testing of Basic

Surface Safety Systems for Offshore Production Platforms, Fourth Edition, September 1,

1986, API Stock No. 811–07180.

§ 250.122(b), (e)(2); § 250.123(a), (b)(2)(i),

(b)(4), (b)(5)(i), (b)(7), (b)(9)(v), (c)(2);

§ 250.124(a), (a)(5); § 250.152(d);

§ 250.154(b)(9); § 250.291(c), (d)(2);

§ 250.292(b)(2), (b)(4)(v); § 250.293(a).

API RP 14E, Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems, Fifth Edition, October 1, 1991, API Stock No. G07185.§ 250.122(e)(3); § 250.291(b)(2), (d)(3).

API RP 14F, Recommended Practice for Design and Installation of Electrical Systems for Offshore Production Platforms, Third Edition, September 1, 1991, API Stock No. G07190.§ 250.53(c); § 250.123(b)(9)(v);

§ 250.292(b)(4)(v).

API RP 14G, Recommended Practice for Fire Prevention and Control on Open Type Offshore

Production Platforms, Third Edition, December 1, 1993, API Stock No. G07194.

§ 250.123(b)(8), (b)(9)(v); § 250.292(b)(3),

(b)(4)(v).

API RP 14H, Recommended Practice for Installation, Maintenance and Repair of Surface Safety Valves and Underwater Safety Valves Offshore, Fourth Edition, July 1, 1994, API Stock

No. G14H04.

§ 250.122(d); § 250.126(d).

API RP 500, Recommended Practice for Classification of Locations for Electrical Installations at

Petroleum Facilities, First Edition, June 1, 1991, API Stock No. G06005.

§ 250.53(b); § 250.122(e)(4)(i);

§ 250.123(b)(9)(i); § 250.291(b)(3); (d)(4)(i);

§ 250.292(b)(4)(i).

API RP 2556, Recommended Practice for Correcting Gauge Tables for Incrustation, Second

Edition, August 1993, API Stock No. H25560.

§ 250.182(l)(4).

API Spec Q1, Specification for Quality Programs, Third Edition, June 1990, API Stock No. 811–

00001a.

§ 250.126(a)(2)(ii).

API Spec 6A, Specification for Wellhead and Christmas Tree Equipment, Seventeenth Edition,

February 1, 1996, API Stock No. G06A17.

§ 250.126 (a)(3); § 250.152(b)(1), (b)(2).

API Spec 6AV1, Specification for Verification Test of Wellhead Surface Safety Valves and Underwater Safety Valves for Offshore Service, First Edition, February 1, 1996, API Stock No.

G06AV1.

§ 250.126(a)(3).

API Spec 6D, Specification for Pipeline Valves (Gate, Plug, Ball, and Check Valves), Twentyfirst Edition, March 31, 1994, API Stock No. G03200.§ 250.152(b)(1).

API Spec 14A, Specification for Subsurface Safety Valve Equipment, Ninth Edition, July 1,

1994, API Stock No. G14A09.

§ 250.126(a)(3).

API Spec 14D, Specification for Wellhead Surface Safety Valves and Underwater Safety

Valves for Offshore Service, Ninth Edition, June 1, 1994, with Errata dated August 1, 1994,

API Stock No. G07183.

§ 250.126(a)(3).

API Standard 2545, Method of Gaging Petroleum and Petroleum Products, October 1965, reaffirmed October 1992; also available as ANSI/American Society of Testing Materials (ASTM)

D 1085–65, API Stock No. H25450.

§ 250.182(l)(4).

API Standard 2551, Standard Method for Measurement and Calibration of Horizontal Tanks,

First Edition, 1965, reaffirmed October 1992; also available as ANSI/ASTM D 1410–65, reapproved 1984, API Stock No. H25510.

§ 250.182(l)(4).

API Standard 2552, Measurement and Calibration of Spheres and Spheroids, First Edition,

1966, reaffirmed October 1992; also available as ANSI/ASTM D 1408–65, reapproved 1984,

API Stock No. H25520.

§ 250.182(l)(4).
Federal Register / Vol. 63, No. 91 /Tuesday, May 12, 1998 /Rules and Regulations 26369

Title of document Incorporated by reference at

API Standard 2555, Method for Liquid Calibration of Tanks, September 1966, reaffirmed October 1992; also available as ANSI/ASTM D 1406–65, reapproved 1984, API Stock No.

H25550.

§ 250.182(l)(4).

MPMS, Chapter 1, Vocabulary, Second Edition, July 1994, API Stock No. H01002 .................... § 250.181.

MPMS, Chapter 2, Tank Calibration, Section 2A, Measurement and Calibration of Upright Cylindrical Tanks by the Manual Strapping Method, First Edition, February 1995, API Stock No.

H022A1.

§ 250.182(l)(4).

MPMS, Chapter 2, Section 2B, Calibration of Upright Cylindrical Tanks Using the Optical Reference Line Method, First Edition, March 1989; also available as ANSI/ASTM D4738–88, API

Stock No. H30023.

§ 250.182(l)(4).

MPMS, Chapter 3, Tank Gauging, Section 1A, Standard Practice for the Manual Gauging of

Petroleum and Petroleum Products, First Edition, December 1994, API Stock No. H031A1.

§ 250.182(l)(4).

MPMS, Chapter 3, Section 1B, Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic Tank Gauging, First Edition, April 1992, API Stock

No. H30060.

§ 250.182(l)(4).

MPMS, Chapter 4, Proving Systems, Section 1, Introduction, First Edition, July 1988, reaffirmed

October 1993, API Stock No. H30081.

§ 250.182(a)(3),(f)(1).

MPMS, Chapter 4, Section 2, Conventional Pipe Provers, First Edition, October 1988, reaffirmed October 1993, API Stock No. H30082.§ 250.182(a)(3),(f)(1).

MPMS, Chapter 4, Section 3, Small Volume Provers, First edition, July 1988, reaffirmed October 1993, API Stock No. H30083.§ 250.182(a)(3),(f)(1).

MPMS, Chapter 4, Section 4, Tank Provers, First Edition, October 1988, reaffirmed October

1993, API Stock No. H30084.

§ 250.182(a)(3),(f)(1).

MPMS, Chapter 4, Section 5, Master-Meter Provers, First Edition, October 1988, reaffirmed

October 1993, API Stock No. H30085.

§ 250.182(a)(3), (f)(1).

MPMS, Chapter 4, Section 6, Pulse Interpolation, First Edition, July 1988, reaffirmed October

1993, API Stock No. H30086.

§ 250.182(a)(3), (f)(1).

MPMS, Chapter 4, Section 7, Field-Standard Test Measures, First Edition, October 1988, API

Stock No. H30087.

§ 250.182(a)(3), (f)(1).

MPMS, Chapter 5, Metering, Section 1, General Considerations for Measurement by Meters,

Third Edition, September 1995, API Stock No. H05013.

§ 250.182(a)(3).

MPMS, Chapter 5, Section 2, Measurement of Liquid Hydrocarbons by Displacement Meters,

Second Edition, November 1987, reaffirmed October 1992, API Stock No. H30102.

§ 250.182(a)(3).

MPMS, Chapter 5, Section 3, Measurement of Liquid Hydrocarbons by Turbine Meters, Third

Edition, September 1995, API Stock No. H05033.

§ 250.182(a)(3).

MPMS, Chapter 5, Section 4, Accessory Equipment for Liquid Meters, Third Edition, September

1995, with Errata, March 1996, API Stock No. H05043.

§ 250.182(a)(3).

MPMS, Chapter 5, Section 5, Fidelity and Security of Flow Measurement Pulsed-Data Transmission Systems, First Edition, June 1982, reaffirmed October 1992, API Stock No. H30105.§ 250.182(a)(3).

MPMS, Chapter 6, Metering Assemblies, Section 1, Lease Automatic Custody Transfer (LACT)

Systems, Second Edition, May 1991, API Stock No. H30121.

§ 250.182(a)(3).

MPMS, Chapter 6, Section 6, Pipeline Metering Systems, Second Edition, May 1991, API

Stock No. H30126.

§ 250.182(a)(3).

MPMS, Chapter 6, Section 7, Metering Viscous Hydrocarbons, Second Edition, May 1991, API

Stock No. H30127.

§ 250.182(a)(3).

MPMS, Chapter 7, Temperature Determination, Section 2, Dynamic Temperature Determination, Second Edition, March 1995, API Stock No. H07022.§ 250.182 (a)(3), (l)(4).

MPMS, Chapter 7, Section 3, Static Temperature Determination Using Portable Electronic

Thermometers, First Edition, July 1985, reaffirmed March 1990, API Stock No. H30143.

§ 250.182 (a)(3), (l)(4).

MPMS, Chapter 8, Sampling, Section 1, Standard Practice for Manual Sampling of Petroleum

and Petroleum Products, Third Edition, October 1995; also available as ANSI/ASTM D 4057–

88, API Stock No. H30161.

§ 250.182 (b)(4)(i), (l)(4).

MPMS, Chapter 8, Section 2, Standard Practice for Automatic Sampling of Liquid Petroleum

and Petroleum Products, Second Edition, October 1995; also available as ANSI/ASTM D

4177, API Stock No. H30162.

§ 250.182 (a)(3), (l)(4).

MPMS, Chapter 9, Density Determination, Section 1, Hydrometer Test Method for Density, Relative Density (Specific Gravity), or API Gravity of Crude Petroleum and Liquid Petroleum

Products, First Edition, June 1981, reaffirmed October 1992; also available as ANSI/ASTM D

1298, API Stock No. H30181.

§ 250.182 (a)(3), (l)(4).

MPMS, Chapter 9, Section 2, Pressure Hydrometer Test Method for Density or Relative Density, First Edition, April 1982, reaffirmed October 1992, API Stock No. H30182.§ 250.182 (a)(3), (l)(4).

MPMS, Chapter 10, Sediment and Water, Section 1, Determination of Sediment in Crude Oils

and Fuel Oils by the Extraction Method, First Edition, April 1981, reaffirmed December 1993;

also available as ANSI/ASTM D 473, API Stock No. H30201.

§ 250.182 (a)(3), (l)(4).

MPMS, Chapter 10, Section 2, Determination of Water in Crude Oil by Distillation Method, First

Edition, April 1981, reaffirmed December 1993; also available as ANSI/ASTM D 4006, API

Stock No. H30202.

§ 250.182 (a)(3), (l)(4).

MPMS, Chapter 10, Section 3, Determination of Water and Sediment in Crude Oil by the Centrifuge Method (Laboratory Procedure), First Edition, April 1981, reaffirmed December 1993;

also available as ANSI/ASTM D 4007, API Stock No. H30203.

§ 250.182 (a)(3), (l)(4).

MPMS, Chapter 10, Section 4, Determination of Sediment and Water in Crude Oil by the Centrifuge Method (Field Procedure), Second Edition, May 1988; also available as ANSI/ASTM D

96, API Stock No. H30204.

§ 250.182 (a)(3), (l)(4).
26370 Federal Register / Vol. 63, No. 91 /Tuesday, May 12, 1998 /Rules and Regulations

Title of document Incorporated by reference at

MPMS, Chapter 11.1, Volume Correction Factors, Volume 1, Table 5A—Generalized Crude

Oils and JP–4 Correction of Observed API Gravity to API Gravity at 60°F, and Table 6A—

Generalized Crude Oils and JP–4 Correction of Observed API Gravity to API Gravity at 60°F,

First Edition, August 1980, reaffirmed October 1993; also available as ANSI/ASTM D 1250,

API Stock No. H27000.

§ 250.182 (a)(3), (g)(3), (l)(4).

MPMS, Chapter 11.2.1, Compressibility Factors for Hydrocarbons: 0–90° API Gravity Range,

First Edition, August 1984, reaffirmed May 1996, API Stock No. H27300.

§ 250.182(a)(3),(g)(4).

MPMS, Chapter 11.2.2, Compressibility Factors for Hydrocarbons: 0.350–0.637 Relative Density (60°F/60°F) and ¥50°F to 140°F Metering Temperature, Second Edition, October 1986,

reaffirmed October 1992; also available as Gas Processors Association (GPA) 8286–86, API

Stock No. H27307.

§ 250.182(a)(3),(g)(4).

MPMS, Chapter 11, Physical Properties Data, Addendum to Section 2.2, Compressibility Factors for Hydrocarbons, Correlation of Vapor Pressure for Commercial Natural Gas Liquids,

First Edition, December 1994; also available as GPA TP–15, API Stock No. H27308.

§ 250.182(a)(3).

MPMS, Chapter 11.2.3, Water Calibration of Volumetric Provers, First Edition, August 1984, reaffirmed, May 1996, API Stock No. H27310.§ 250.182(f)(1).

MPMS, Chapter 12, Calculation of Petroleum Quantities, Section 2, Calculation of Petroleum

Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Including Parts 1 and 2, Second Edition, May 1995; also available as ANSI/API MPMS 12.2–1981,

API Stock No. H30302.

§ 250.182(a)(3), (g)(1), (g)(2)

MPMS, Chapter 14, Natural Gas Fluids Measurement, Section 3, Concentric Square-Edged

Orifice Meters, Part 1, General Equations and Uncertainty Guidelines, Third Edition, September 1990; also available as ANSI/API 2530, Part 1, 1991, API Stock No. H30350.

§ 250.183(b)(2).

MPMS, Chapter 14, Section 3, Part 2, Specification and Installation Requirements, Third Edition, February 1991; also available as ANSI/API 2530, Part 2, 1991, API Stock No. H30351.§ 250.183(b)(2).

MPMS, Chapter 14, Section 3, Part 3, Natural Gas Applications, Third Edition, August 1992;

also available as ANSI/API 2530, Part 3, API Stock No. H30353.

§ 250.183(b)(2).

MPMS, Chapter 14, Section 5, Calculation of Gross Heating Value, Relative Density, and Compressibility Factor for Natural Gas Mixtures From Compositional Analysis, Revised, 1996;

also available as ANSI/API MPMS 14.5–1981, order from Gas Processors Association, 6526

East 60th Street, Tulsa, Oklahoma 74145.

§ 250.183(b)(2).

MPMS, Chapter 14, Section 6, Continuous Density Measurement, Second Edition, April 1991,

API Stock No. H30346.

§ 250.183(b)(2).

MPMS, Chapter 14, Section 8, Liquefied Petroleum Gas Measurement, First Edition, February

1983, reaffirmed May 1996, API Stock No. H30348.

§ 250.183(b)(2).

MPMS, Chapter 20, Section 1, Allocation Measurement, First Edition, September 1993, API

Stock No. H30701.

§ 250.182(k)(1).

MPMS, Chapter 21, Section 1, Electronic Gas Measurement, First Edition, September 1993,

API Stock No. H30730.

§ 250.183(b)(4).

ASTM Standard C33–93, Standard Specification for Concrete Aggregates including Nonmandatory Appendix.§ 250.138(b)(4)(i).

ASTM Standard C94–96, Standard Specification for Ready-Mixed Concrete ............................... § 250.138(e)(2)(i).

ASTM Standard C150–95a, Standard Specification for Portland Cement ..................................... § 250.138(b)(2)(i).

ASTM Standard C330–89, Standard Specification for Lightweight Aggregates for Structural

Concrete.

§ 250.138(b)(4)(i).

ASTM Standard C595–94, Standard Specification for Blended Hydraulic Cements ..................... § 250.138(b)(2)(i).

D1.1–96, Structural Welding Code—Steel, 1996, including Commentary ..................................... § 250.137(b)(1)(i).

DI.4–79, Structural Welding Code—Reinforcing Steel, 1979 ......................................................... § 250.138 (e)(3)(ii).

NACE Standard MR–01–75–96, Sulfide Stress Cracking Resistant Metallic Materials for Oil

Field Equipment, January 1996.

§ 250.67 (p)(2).

NACE Standard RP 0176–94, Standard Recommended Practice, Corrosion Control of Steel

Fixed Offshore Platforms Associated with Petroleum Production.

§ 250.137(d).

3. Revise Subpart L to read as follows:

Subpart L—Oil and Gas Production

Measurement Surface Commingling, and

Security

Sec.

250.180 Question index table.

250.181 Definitions.

250.182 Liquid hydrocarbon measurement.

250.183 Gas measurement.

250.184 Surface commingling.

250.185 Site security.

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.

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 calibrating a master meter used in royalty meter provings? ...................................................... § 250.182(e).

6. What are the requirements for calibrating mechanical-displacement provers and tank provers? .............................................. § 250.182(f).
Federal Register / Vol. 63, No. 91 /Tuesday, May 12, 1998 /Rules and Regulations 26371

Frequently asked questions CFR citation

7. What correction factors must I use when proving meters with a mechanical displacement prover, tank prover, 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 a liquid hydrocarbon royalty meter need to be taken out of service, and what must I do? ... § 250.182(i).

10. How must I correct gross liquid hydrocarbon volumes to standard conditions? ....................................................................... § 250.182(j).

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

12. What are the requirements for royalty and inventory tank facilities ? ....................................................................................... § 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 I do if a gas meter is out of calibration or malfunctioning? ..................................................................................... § 250.183(d).

17. What are the requirements when natural gas from a Federal lease on the OCS is transferred to a gas plant before royalty

determination?.

§ 250.183(e).

18. What are the requirements for measuring gas lost or used on a lease? .................................................................................. § 250.183(f).

19. What are the requirements for the surface commingling of production? ................................................................................... § 250.184(a).

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

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

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

§ 250.181 Definitions.

Terms not defined in this section have

the meanings given in the applicable

chapter of the API MPMS, which is

incorporated by reference in 30 CFR

250.1. Terms used in Subpart L have the

following meaning:

Allocation meter—a meter used to

determine the portion of hydrocarbons

attributable to one or more platforms,

leases, units, or wells, in relation to the

total production from a royalty or

allocation measurement point.

API MPMS—the American Petroleum

Institute’s Manual of Petroleum

Measurement Standards, chapters 1, 20,

and 21.

British Thermal Unit (Btu)—the

amount of heat needed to raise the

temperature of one pound of water from

59.5 degrees Fahrenheit (59.5 °F) to 60.5

degrees Fahrenheit (60.5 °F) at standard

pressure base (14.73 pounds per square

inch absolute (psia)).

Calibration—testing (verifying) and

correcting, if necessary, a measuring

device to industry accepted,

manufacturer’s recommended, or

regulatory required standard of

accuracy.

Compositional Analysis—separating

mixtures into identifiable components

expressed in mole percent.

Gas lost—gas that is neither sold nor

used on the lease or unit nor used

internally by the producer.

Gas processing plant—an installation

that uses any process designed to

remove elements or compounds

(hydrocarbon and non-hydrocarbon)

from gas, including absorption,

adsorption, or refrigeration. Processing

does not include treatment operations,

including those necessary to put gas

into marketable conditions such as

natural pressure reduction, mechanical

separation, heating, cooling,

dehydration, desulphurization, and

compression. The changing of pressures

or temperatures in a reservoir is not

processing.

Gas processing plant statement—a

monthly statement showing the volume

and quality of the inlet or field gas

stream and the plant products recovered

during the period, volume of plant fuel,

flare and shrinkage, and the allocation

of these volumes to the sources of the

inlet stream.

Gas royalty meter malfunction—an

error in any component of the gas

measurement system which exceeds

contractual tolerances.

Gas volume statement—a monthly

statement showing gas measurement

data, including the volume (Mcf) and

quality (Btu) of natural gas which

flowed through a meter.

Inventory tank—a tank in which

liquid hydrocarbons are stored prior to

royalty measurement. The measured

volumes are used in the allocation

process.

Liquid hydrocarbons (free liquids)—

hydrocarbons which exist in liquid form

at standard conditions after passing

through separating facilities.

Malfunction factor—a liquid

hydrocarbon royalty meter factor that

differs from the previous meter factor by

an amount greater than 0.0025.

Natural gas—a highly compressible,

highly expandable mixture of

hydrocarbons which occurs naturally in

a gaseous form and passes a meter in

vapor phase.

Operating meter—a royalty or

allocation meter that is used for gas or

liquid hydrocarbon measurement for

any period during a calibration cycle.

Pressure base—the pressure at which

gas volumes and quality are reported.

The standard pressure base is 14.73

psia.

Prove—to determine (as in meter

proving) the relationship between the

volume passing through a meter at one

set of conditions and the indicated

volume at those same conditions.

Pipeline (retrograde) condensate—

liquid hydrocarbons which drop out of

the separated gas stream at any point in

a pipeline during transmission to shore.

Royalty meter—a meter approved for

the purpose of determining the volume

of gas, oil, or other components

removed, saved, or sold from a Federal

lease.

Royalty tank—an approved tank in

which liquid hydrocarbons are

measured and upon which royalty

volumes are based.

Run ticket—the invoice for liquid

hydrocarbons measured at a royalty

point.

Sales meter—a meter at which

custody transfer takes place (not

necessarily a royalty meter).

Seal—a device or approved method

used to prevent tampering with royalty

measurement components.

Standard conditions—atmospheric

pressure of 14.73 pounds per square

inch absolute (psia) and 60° F.

Surface commingling—the surface

mixing of production from two or more

leases or units prior to measurement for

royalty purposes.

Temperature base—the temperature at

which gas and liquid hydrocarbon

volumes and quality are reported. The

standard temperature base is 60° F.

You or your—the lessee or the

operator or other lessees’ representative

engaged in operations in the Outer

Continental Shelf (OCS).

§ 250.182 Liquid hydrocarbon

measurement.

(a) What are the requirements for

measuring liquid hydrocarbons? You

must:

(1) Submit a written application to,

and obtain approval from, the Regional
26372 Federal Register / Vol. 63, No. 91 /Tuesday, May 12, 1998 /Rules and Regulations

Supervisor before commencing liquid

hydrocarbon production or making

changes to previously approved

measurement procedures;

(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

incorporated by reference in 30 CFR

250.1, when obtaining net standard

volume and associated measurement

parameters; and

(4) When requested by the Regional

Supervisor, provide the pipeline

(retrograde) condensate volumes as

allocated to the individual leases or

units.

(b) What are the requirements for

liquid hydrocarbon royalty meters? You

must:

(1) Ensure that the royalty meter

facilities include the following

approved components (or other MMSapproved components) which must be

compatible with their connected

systems:

(i) A meter equipped with a nonreset

totalizer;

(ii) A calibrated mechanical

displacement (pipe) prover, master

meter, or tank prover;

(iii) A proportional-to-flow sampling

device pulsed by the meter output;

(iv) A temperature measurement or

temperature compensation device; and

(v) A sediment and water monitor

with a probe located upstream of the

divert valve.

(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 being

subjected to 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

(in accordance with the API MPMS as

incorporated by reference in 30 CFR

250.1);

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

device to allow complete mixing of the

sample before removal from the

container; and

(iii) The sample probe is in the center

half of the pipe diameter in a vertical

run and is located at least three pipe

diameters downstream of any pipe

fitting within a region of turbulent flow.

The sample probe can be located in a

horizontal pipe if adequate stream

conditioning such as power mixers or

static mixers are installed upstream of

the probe according to the

manufacturer’s instructions.

(c) What are the requirements for run

tickets? You must:

(1) For royalty meters, ensure that the

run tickets clearly identify all observed

data, all correction factors not included

in the meter factor, and the net standard

volume.

(2) For royalty tanks, ensure that the

run tickets clearly identify all observed

data, all applicable correction factors,

on/off seal numbers, and the net

standard volume.

(3) Pull a run ticket at the beginning

of the month and immediately after

establishing the monthly meter factor or

a malfunction meter factor.

(4) Send all run tickets for royalty

meters and tanks to the Regional

Supervisor within 15 days after the end

of the month;

(d) What are the requirements for

liquid hydrocarbon royalty meter

provings? You must:

(1) Permit MMS representatives to

witness provings;

(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 monthly,

but the time between meter factor

determinations must not exceed 42

days;

(4) Obtain approval from the Regional

Supervisor before proving on a schedule

other than monthly; and

(5) 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

calibrating a master meter used in

royalty meter provings? You must:

(1) Calibrate the master meter to

obtain a master 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

monthly, 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 meter factor differences

of no greater than 0.0002. Lessees must

use the average of the two (or the five)

runs that produced acceptable results to

compute the master meter factor;

(5) Install the master meter upstream

of any back-pressure or reverse flow

check valves associated with the

operating meter. However, the master

meter may be installed either upstream

or downstream of the operating meter;

and

(6) Keep a copy of the master meter

calibration report at your field location

for 2 years.

(f) What are the requirements for

calibrating mechanical-displacement

provers and tank provers? You must:

(1) Calibrate mechanical-displacement

provers and tank provers at least once

every 5 years according to the API

MPMS as incorporated by reference 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 I

use when proving meters with a

mechanical-displacement prover, tank

prover, or master meter? Calculate the

following correction factors using the

API MPMS as referenced in 30 CFR 250,

Subpart A:

(1) The change in prover volume due

to the effect of temperature on steel

(Cts);

(2) The change in prover volume due

to the effect of pressure on steel (Cps);

(3) The change in liquid volume due

to the effect of temperature on a liquid

(Ctl); and

(4) The change in liquid volume due

to the effect of pressure on a liquid

(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 difference

between individual runs of no greater

than .05 percent. You must use the

average of the five accepted runs to

compute the meter factor.

(2) If you use a master meter, you

must record proof runs until three

consecutive runs produce a total meter
Federal Register / Vol. 63, No. 91 /Tuesday, May 12, 1998 /Rules and Regulations 26373

factor difference of no greater than

0.0005. The flow rate through the meters

during the proving must be within 10

percent of the rate at which the line

meter will operate. The final meter

factor is determined by averaging the

meter factors of the three runs;

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

record proof runs until two consecutive

runs produce a meter factor difference

of no greater than .0005. The final meter

factor is determined by averaging the

meter factors of the two runs; and

(4) You must apply operating meter

factors forward starting with the date of

the proving.

(i) Under what circumstances does a

liquid hydrocarbon royalty meter need

to be taken out of service, and what

must I do? (1) If the difference between

the meter factor and the previous factor

exceeds 0.0025 it is a malfunction

factor, and you must:

(i) Remove the meter from service and

inspect it for damage or wear;

(ii) Adjust or repair the meter, 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) Indicate that a meter malfunction

occurred and show all appropriate

remarks regarding subsequent repairs or

adjustments on the proving report.

(2) If a meter fails to register

production, you must:

(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 and report unregistered

production on the run ticket.

(3) If the results of a royalty meter

proving exceed the run tolerance criteria

and all measures excluding the

adjustment or repair of the meter cannot

bring results within tolerance, you must:

(i) Establish a factor using proving

results made before any adjustment 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 I correct gross liquid

hydrocarbon volumes to standard

conditions? To correct gross liquid

hydrocarbon volumes to standard

conditions, you must:

(1) Include Cpl factors in the meter

factor calculation or list and apply them

on the appropriate run ticket.

(2) List 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?

For liquid hydrogen allocation meters

you must:

(1) Take samples continuously

proportional to flow or daily (use the

procedure in the applicable chapter of

the API MPMS as incorporated by

reference in 30 CFR 250.1;

(2) For turbine meters, take the

sample proportional to the flow only;

(3) Prove allocation meters monthly if

they measure 50 or more barrels per day

per meter; or

(4) Prove allocation meters quarterly if

they measure less than 50 barrels 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 the

meter factor differs from the previous

meter factor by more than 2 percent and

less than 7 percent;

(7) For turbine meters, remove from

service, inspect and reprove the meter if

the factor differs from the previous

meter factor by more than 2 percent and

less than 7 percent;

(8) Repair and reprove, or replace and

prove the meter if the meter factor

differs from the previous meter factor by

7 percent or more; and

(9) Permit MMS representatives to

witness provings.

(l) What are the requirements for

royalty and inventory tank facilities?

You must:

(1) Equip each royalty and inventory

tank with a vapor-tight thief hatch, a

vent-line valve, and a fill line designed

to minimize free fall and splashing;

(2) For royalty tanks, submit a

complete set of calibration charts (tank

tables) to the Regional Supervisor before

using the tanks for royalty

measurement;

(3) For inventory tanks, retain the

calibration charts for as long as the

tanks are in use and submit them to the

Regional Supervisor upon request; and

(4) Obtain the volume and other

measurement parameters by using

correction factors and procedures in the

API MPMS as incorporated by reference

in 30 CFR 250.1.

§ 250.183 Gas measurement.

(a) To which meters do MMS

requirements for gas measurement

apply? MMS requirements for gas

measurements apply to all OCS gas

royalty and allocation meters.

(b) What are the requirements for

measuring gas? You must:

(1) Submit a written application to

and obtain approval from the Regional

Supervisor before commencing gas

production or making changes to

previously approved measurement

procedures.

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

test measurement equipment to ensure

accurate and verifiable measurement.

You must follow the recommendations

in API MPMS as incorporated by

reference in 30 CFR 250.1.

(3) Ensure that the measurement

components demonstrate consistent

levels of accuracy throughout the

system.

(4) Equip the meter with a chart or

electronic data recorder. If an electronic

data recorder is used, you must follow

the recommendations in API MPMS as

referenced in 30 CFR 250.1.

(5) Take proportional-to-flow or spot

samples upstream or downstream of the

meter at least once every 6 months.

(6) When requested by the Regional

Supervisor, provide available

information on the gas quality.

(7) Ensure that standard conditions

for reporting gross heating value Btu are

at a base temperature of 60° F and at a

base pressure of 14.73 psia and reflect

the same degree of water saturation as

in the gas volume.

(8) When requested by the Regional

Supervisor, submit copies of gas volume

statements for each requested gas meter.

Show whether gas volumes and gross

Btu heating values are reported at

saturated or unsaturated conditions; and

(9) When requested by the Regional

Supervisor, provide volume and quality

statements on dispositions other than

those on the gas volume statement.

(c) What are the requirements for gas

meter calibrations? You must:

(1) Calibrate meters monthly, but do

not exceed 42 days between

calibrations;

(2) Calibrate each meter by using the

manufacturer’s specifications;

(3) Conduct calibrations as close as

possible to the average hourly rate of

flow since the last calibration;

(4) Retain calibration reports at the

field location for 2 years, and send the

reports to the Regional Supervisor upon

request; and

(5) Permit MMS representatives to

witness calibrations.

(d) What must I do if a gas meter is

out of calibration or malfunctioning? If

a gas meter is out of calibration or

malfunctioning, you must:

(1) If the readings are greater than the

contractual tolerances, 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.

(ii) If the duration of the error cannot

be determined, apply the volume

adjustment to one-half of the time
26374 Federal Register / Vol. 63, No. 91 /Tuesday, May 12, 1998 /Rules and Regulations

elapsed since the last calibration or 21

days, whichever is less.

(e) What are the requirements when

natural gas from a Federal lease on the

OCS is transferred to a gas plant before

royalty determination? If natural gas

from a Federal lease on the OCS is

transferred to a gas plant before royalty

determination:

(1) You must provide the following to

the Regional Supervisor upon request:

(i) A copy of the monthly gas

processing plant allocation statement;

and

(ii) Gross heating values of the inlet

and residue streams when not reported

on the gas plant statement.

(2) You must permit MMS to inspect

the measurement and sampling

equipment of natural gas processing

plants that process Federal production.

(f) What are the requirements for

measuring gas lost or used on a lease?

(1) You must either measure or estimate

the volume of gas lost or used on a

lease.

(2) If you measure the volume,

document the measurement equipment

used and include the volume measured.

(3) If you estimate the volume,

document the estimating method, the

data used, and the volumes estimated.

(4) You must keep the documentation,

including the volume data, easily

obtainable for inspection at the field

location for at least 2 years, and must

retain the documentation at a location of

your choosing for at least 7 years after

the documentation is generated, subject

to all other document retention and

production requirements in 30 U.S.C.

1713 and 30 CFR part 212.

(5) Upon the request of the Regional

Supervisor, you must provide copies of

the records.

§ 250.184 Surface commingling.

(a) What are the requirements for the

surface commingling of production?

You must:

(1) Submit a written application to

and obtain approval from the Regional

Supervisor before commencing the

commingling of production or making

changes to previously approved

commingling applications.

(2) Upon the request of the Regional

Supervisor, lessees who deliver State

lease production into a Federal

commingling system must provide

volumetric or fractional analysis data on

the State lease production through the

designated system operator.

(b) What are the requirements for a

periodic well test used for allocation?

You must:

(1) Conduct a well test at least once

every 2 months unless the Regional

Supervisor approves a different

frequency;

(2) Follow the well test procedures in

30 CFR part 250, Subpart K; 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? You must:

(1) Protect Federal production against

production loss or theft;

(2) Post a sign at each royalty or

inventory tank which is used in the

royalty determination process. 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 any

component of the royalty measurement

facility; and

(iii) Falsifying production

measurements.

(b) What are the requirements for

using seals? You must:

(1) Seal the following components of

liquid hydrocarbon royalty meter

installations to ensure that tampering

cannot occur without destroying the

seal:

(i) Meter component connections from

the base of the meter up to and

including the register;

(ii) Sampling systems including

packing device, fittings, sight glass, and

container lid;

(iii) Temperature and gravity

compensation device components;

(iv) All valves on lines leaving a

royalty or inventory storage tank,

including load-out line valves, drainline valves, and connection-line valves

between royalty and non-royalty tanks;

and

(v) Any additional components

required by the Regional Supervisor.

(2) Seal all bypass valves of gas

royalty and allocation meters.

(3) Number and track the seals and

keep the records at the field location for

at least 2 years; and

(4) Make the records of seals available

for MMS inspection.

[FR Doc. 98–11803 Filed 5–11–98; 8:45 am]

BILLING CODE 4310–MR–P