[Federal Register Volume 63, Number 91 (Tuesday, May 12, 1998)]
[Rules and Regulations]
[Pages 26362-26374]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 98-11803]



[[Page 26361]]

_______________________________________________________________________

Part IV





Department of the Interior





_______________________________________________________________________



Minerals Management Service



_______________________________________________________________________



30 CFR Parts 202, et al.

Royalties on Gas, Gas Analysis Reports, Oil and Gas Production 
Measurement, Surface Commingling, and Security; Final Rule

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

[[Page 26362]]



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 Sec. 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

[[Page 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

[[Page 26364]]

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 Sec. 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 
Sec. 250.183 (f) (1) through (5) because it relates to gas measurement.

[[Page 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 
Sec. 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.

----------------------------------------------------------------------------------------------------------------
                                            Have the OMB                                                        
      The information collections in          approval                              and                         
                                               number                                                           
----------------------------------------------------------------------------------------------------------------
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.

[[Page 26366]]

    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 Secs. 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 Sec. 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.

[[Page 26367]]

30 CFR Part 216

    Coal, Continental shelf, Geothermal energy, Government contracts, 
Indian lands, Mineral royalties, Natural gas, Penalties, Petroleum, 
Public lands-mineral 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 Sec. 202.152(a)(1) to read as follows:


Sec. 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 deg. 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 Sec. 216.54 to read as follows:


Sec. 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 Sec. 250.1 to read as follows:


Sec. 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 Secs. 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,     American Petroleum Institute, 1220 L     
 Specs, Standards, Manual of    Street N.W., Washington, D.C. 20005.    
 Petroleum Measurement                                                  
 Standards (MPMS) chapters.                                             
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.                                  
------------------------------------------------------------------------


[[Page 26368]]

    (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.

------------------------------------------------------------------------
                                               Incorporated by reference
              Title of document                            at           
------------------------------------------------------------------------
ACI Standard 318-95, Building Code             Sec.  250.138(b)(4)(i),  
 Requirements for Reinforced Concrete, plus     (b)(6)(i), (b)(7),      
 Commentary on Building Code Requirements for   (b)(8)(i), (b)(9),      
 Reinforced Concrete (ACI 318R-95).             (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    Sec.  250.130(g);Sec.  25
 and Construction of Fixed Offshore Concrete    0.138 (c)(2), (c)(3).   
 Structures, 1984.                                                      
AISC Standard, Specification for Structural    Sec.  250.137(b)(1)(ii), 
 Steel for Buildings, Allowable Stress Design   (c)(4)(ii), (c)(4)(vii).
 and Plastic Design, June 1, 1989, with                                 
 Commentary.                                                            
ANSI/ASME Boiler and Pressure Vessel Code,     Sec.  250.123(b)(1),     
 Section I, Power Boilers including             (b)(1)(i); Sec.         
 Appendices, 1995 Edition.                      250.292(b)(1),          
                                                (b)(1)(i).              
ANSI/ASME Boiler and Pressure Vessel Code,     Sec.  250.123(b)(1),     
 Section IV, Heating Boilers including          (b)(1)(i); Sec.         
 Nonmandatory Appendices A, B, C, D, E, F, H,   250.292(b)(1),          
 I, and J, and the Guide to Manufacturers       (b)(1)(i).              
 Data Report Forms, 1995 Edition.                                       
ANSI/ASME Boiler and Pressure Vessel Code,     Sec.  250.123(b)(1),     
 Section VIII, Pressure Vessels, Divisions 1    (b)(1)(i); Sec.         
 and 2, including Nonmandatory Appendices,      250.292(b)(1),          
 1995 Edition.                                  (b)(1)(i).              
ANSI/ASME B 16.5-1988 (including Errata) and   Sec.  250.152(b)(2).     
 B 16.5a-1992 Addenda, Pipe Flanges and                                 
 Flanged Fittings.                                                      
ANSI/ASME B 31.8-1995, Gas Transmission and    Sec.  250.152(a).        
 Distribution Piping Systems.                                           
ANSI Z88.2--1992, American National Standard   Sec.  250.67(g)(4)(iv),  
 for Respiratory Protection.                    (j)(13)(ii).            
ANSI/ASME SPPE-1-1994 and SPPE-1d-1996,        Sec.  250.126(a)(2)(ii). 
 ADDENDA, Quality Assurance and Certification                           
 of Safety and Pollution Prevention Equipment                           
 Used in Offshore Oil and Gas Operations.                               
API RP 2A, Recommended Practice for Planning,  Sec.  250.130(g); Sec.   
 Designing and Constructing Fixed Offshore      250.142(a).             
 Platforms Working Stress Design, Nineteenth                            
 Edition, August 1, 1991, API Stock No. 811-                            
 00200.                                                                 
API RP 2D, Recommended Practice for Operation  Sec.  250.20(c); Sec.    
 and Maintenance of Offshore Cranes, Third      250.260(g).             
 Edition, June 1, 1995, API Stock No. G02D03.                           
API RP 14B, Recommended Practice for Design,   Sec.  250.121(e)(4); Sec.
 Installation, Repair and Operation of           250.124(a)(1)(i); Sec. 
 Subsurface Safety Valve Systems, Fourth        250.126(d).             
 Edition, July 1, 1994, with Errata dated                               
 June 1996, API Stock No. G14B04.                                       
API RP 14C, Recommended Practice for           Sec.  250.122(b), (e)(2);
 Analysis, Design, Installation and Testing     Sec.  250.123(a),       
 of Basic Surface Safety Systems for Offshore   (b)(2)(i), (b)(4),      
 Production Platforms, Fourth Edition,          (b)(5)(i), (b)(7),      
 September 1, 1986, API Stock No. 811-07180.    (b)(9)(v), (c)(2); Sec. 
                                                250.124(a), (a)(5); Sec.
                                                 250.152(d); Sec.       
                                                250.154(b)(9); Sec.     
                                                250.291(c), (d)(2); Sec.
                                                 250.292(b)(2),         
                                                (b)(4)(v); Sec.         
                                                250.293(a).             
API RP 14E, Recommended Practice for Design    Sec.  250.122(e)(3); Sec.
 and Installation of Offshore Production         250.291(b)(2), (d)(3). 
 Platform Piping Systems, Fifth Edition,                                
 October 1, 1991, API Stock No. G07185.                                 
API RP 14F, Recommended Practice for Design    Sec.  250.53(c); Sec.    
 and Installation of Electrical Systems for     250.123(b)(9)(v); Sec.  
 Offshore Production Platforms, Third           250.292(b)(4)(v).       
 Edition, September 1, 1991, API Stock No.                              
 G07190.                                                                
API RP 14G, Recommended Practice for Fire      Sec.  250.123(b)(8),     
 Prevention and Control on Open Type Offshore   (b)(9)(v); Sec.         
 Production Platforms, Third Edition,           250.292(b)(3),          
 December 1, 1993, API Stock No. G07194.        (b)(4)(v).              
API RP 14H, Recommended Practice for           Sec.  250.122(d); Sec.   
 Installation, Maintenance and Repair of        250.126(d).             
 Surface Safety Valves and Underwater Safety                            
 Valves Offshore, Fourth Edition, July 1,                               
 1994, API Stock No. G14H04.                                            
API RP 500, Recommended Practice for           Sec.  250.53(b); Sec.    
 Classification of Locations for Electrical     250.122(e)(4)(i); Sec.  
 Installations at Petroleum Facilities, First   250.123(b)(9)(i); Sec.  
 Edition, June 1, 1991, API Stock No. G06005.   250.291(b)(3);          
                                                (d)(4)(i); Sec.         
                                                250.292(b)(4)(i).       
API RP 2556, Recommended Practice for          Sec.  250.182(l)(4).     
 Correcting Gauge Tables for Incrustation,                              
 Second Edition, August 1993, API Stock No.                             
 H25560.                                                                
API Spec Q1, Specification for Quality         Sec.  250.126(a)(2)(ii). 
 Programs, Third Edition, June 1990, API                                
 Stock No. 811-00001a.                                                  
API Spec 6A, Specification for Wellhead and    Sec.  250.126 (a)(3);    
 Christmas Tree Equipment, Seventeenth          Sec.  250.152(b)(1),    
 Edition, February 1, 1996, API Stock No.       (b)(2).                 
 G06A17.                                                                
API Spec 6AV1, Specification for Verification  Sec.  250.126(a)(3).     
 Test of Wellhead Surface Safety Valves and                             
 Underwater Safety Valves for Offshore                                  
 Service, First Edition, February 1, 1996,                              
 API Stock No. G06AV1.                                                  
API Spec 6D, Specification for Pipeline        Sec.  250.152(b)(1).     
 Valves (Gate, Plug, Ball, and Check Valves),                           
 Twenty-first Edition, March 31, 1994, API                              
 Stock No. G03200.                                                      
API Spec 14A, Specification for Subsurface     Sec.  250.126(a)(3).     
 Safety Valve Equipment, Ninth Edition, July                            
 1, 1994, API Stock No. G14A09.                                         
API Spec 14D, Specification for Wellhead       Sec.  250.126(a)(3).     
 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.                                            
API Standard 2545, Method of Gaging Petroleum  Sec.  250.182(l)(4).     
 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.                                
API Standard 2551, Standard Method for         Sec.  250.182(l)(4).     
 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.                                                                
API Standard 2552, Measurement and             Sec.  250.182(l)(4).     
 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.                                            

[[Page 26369]]

                                                                        
API Standard 2555, Method for Liquid           Sec.  250.182(l)(4).     
 Calibration of Tanks, September 1966,                                  
 reaffirmed October 1992; also available as                             
 ANSI/ASTM D 1406-65, reapproved 1984, API                              
 Stock No. H25550.                                                      
MPMS, Chapter 1, Vocabulary, Second Edition,   Sec.  250.181.           
 July 1994, API Stock No. H01002.                                       
MPMS, Chapter 2, Tank Calibration, Section     Sec.  250.182(l)(4).     
 2A, Measurement and Calibration of Upright                             
 Cylindrical Tanks by the Manual Strapping                              
 Method, First Edition, February 1995, API                              
 Stock No. H022A1.                                                      
MPMS, Chapter 2, Section 2B, Calibration of    Sec.  250.182(l)(4).     
 Upright Cylindrical Tanks Using the Optical                            
 Reference Line Method, First Edition, March                            
 1989; also available as ANSI/ASTM D4738-88,                            
 API Stock No. H30023.                                                  
MPMS, Chapter 3, Tank Gauging, Section 1A,     Sec.  250.182(l)(4).     
 Standard Practice for the Manual Gauging of                            
 Petroleum and Petroleum Products, First                                
 Edition, December 1994, API Stock No. H031A1.                          
MPMS, Chapter 3, Section 1B, Standard          Sec.  250.182(l)(4).     
 Practice for Level Measurement of Liquid                               
 Hydrocarbons in Stationary Tanks by                                    
 Automatic Tank Gauging, First Edition, April                           
 1992, API Stock No. H30060.                                            
MPMS, Chapter 4, Proving Systems, Section 1,   Sec.  250.182(a)(3),(f)(1
 Introduction, First Edition, July 1988,        ).                      
 reaffirmed October 1993, API Stock No.                                 
 H30081.                                                                
MPMS, Chapter 4, Section 2, Conventional Pipe  Sec.  250.182(a)(3),(f)(1
 Provers, First Edition, October 1988,          ).                      
 reaffirmed October 1993, API Stock No.                                 
 H30082.                                                                
MPMS, Chapter 4, Section 3, Small Volume       Sec.  250.182(a)(3),(f)(1
 Provers, First edition, July 1988,             ).                      
 reaffirmed October 1993, API Stock No.                                 
 H30083.                                                                
MPMS, Chapter 4, Section 4, Tank Provers,      Sec.  250.182(a)(3),(f)(1
 First Edition, October 1988, reaffirmed        ).                      
 October 1993, API Stock No. H30084.                                    
MPMS, Chapter 4, Section 5, Master-Meter       Sec.  250.182(a)(3),     
 Provers, First Edition, October 1988,          (f)(1).                 
 reaffirmed October 1993, API Stock No.                                 
 H30085.                                                                
MPMS, Chapter 4, Section 6, Pulse              Sec.  250.182(a)(3),     
 Interpolation, First Edition, July 1988,       (f)(1).                 
 reaffirmed October 1993, API Stock No.                                 
 H30086.                                                                
MPMS, Chapter 4, Section 7, Field-Standard     Sec.  250.182(a)(3),     
 Test Measures, First Edition, October 1988,    (f)(1).                 
 API Stock No. H30087.                                                  
MPMS, Chapter 5, Metering, Section 1, General  Sec.  250.182(a)(3).     
 Considerations for Measurement by Meters,                              
 Third Edition, September 1995, API Stock No.                           
 H05013.                                                                
MPMS, Chapter 5, Section 2, Measurement of     Sec.  250.182(a)(3).     
 Liquid Hydrocarbons by Displacement Meters,                            
 Second Edition, November 1987, reaffirmed                              
 October 1992, API Stock No. H30102.                                    
MPMS, Chapter 5, Section 3, Measurement of     Sec.  250.182(a)(3).     
 Liquid Hydrocarbons by Turbine Meters, Third                           
 Edition, September 1995, API Stock No.                                 
 H05033.                                                                
MPMS, Chapter 5, Section 4, Accessory          Sec.  250.182(a)(3).     
 Equipment for Liquid Meters, Third Edition,                            
 September 1995, with Errata, March 1996, API                           
 Stock No. H05043.                                                      
MPMS, Chapter 5, Section 5, Fidelity and       Sec.  250.182(a)(3).     
 Security of Flow Measurement Pulsed-Data                               
 Transmission Systems, First Edition, June                              
 1982, reaffirmed October 1992, API Stock No.                           
 H30105.                                                                
MPMS, Chapter 6, Metering Assemblies, Section  Sec.  250.182(a)(3).     
 1, Lease Automatic Custody Transfer (LACT)                             
 Systems, Second Edition, May 1991, API Stock                           
 No. H30121.                                                            
MPMS, Chapter 6, Section 6, Pipeline Metering  Sec.  250.182(a)(3).     
 Systems, Second Edition, May 1991, API Stock                           
 No. H30126.                                                            
MPMS, Chapter 6, Section 7, Metering Viscous   Sec.  250.182(a)(3).     
 Hydrocarbons, Second Edition, May 1991, API                            
 Stock No. H30127.                                                      
MPMS, Chapter 7, Temperature Determination,    Sec.  250.182 (a)(3),    
 Section 2, Dynamic Temperature                 (l)(4).                 
 Determination, Second Edition, March 1995,                             
 API Stock No. H07022.                                                  
MPMS, Chapter 7, Section 3, Static             Sec.  250.182 (a)(3),    
 Temperature Determination Using Portable       (l)(4).                 
 Electronic Thermometers, First Edition, July                           
 1985, reaffirmed March 1990, API Stock No.                             
 H30143.                                                                
MPMS, Chapter 8, Sampling, Section 1,          Sec.  250.182 (b)(4)(i), 
 Standard Practice for Manual Sampling of       (l)(4).                 
 Petroleum and Petroleum Products, Third                                
 Edition, October 1995; also available as                               
 ANSI/ASTM D 4057-88, API Stock No. H30161.                             
MPMS, Chapter 8, Section 2, Standard Practice  Sec.  250.182 (a)(3),    
 for Automatic Sampling of Liquid Petroleum     (l)(4).                 
 and Petroleum Products, Second Edition,                                
 October 1995; also available as ANSI/ASTM D                            
 4177, API Stock No. H30162.                                            
MPMS, Chapter 9, Density Determination,        Sec.  250.182 (a)(3),    
 Section 1, Hydrometer Test Method for          (l)(4).                 
 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.                                                      
MPMS, Chapter 9, Section 2, Pressure           Sec.  250.182 (a)(3),    
 Hydrometer Test Method for Density or          (l)(4).                 
 Relative Density, First Edition, April 1982,                           
 reaffirmed October 1992, API Stock No.                                 
 H30182.                                                                
MPMS, Chapter 10, Sediment and Water, Section  Sec.  250.182 (a)(3),    
 1, Determination of Sediment in Crude Oils     (l)(4).                 
 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.                                             
MPMS, Chapter 10, Section 2, Determination of  Sec.  250.182 (a)(3),    
 Water in Crude Oil by Distillation Method,     (l)(4).                 
 First Edition, April 1981, reaffirmed                                  
 December 1993; also available as ANSI/ASTM D                           
 4006, API Stock No. H30202.                                            
MPMS, Chapter 10, Section 3, Determination of  Sec.  250.182 (a)(3),    
 Water and Sediment in Crude Oil by the         (l)(4).                 
 Centrifuge Method (Laboratory Procedure),                              
 First Edition, April 1981, reaffirmed                                  
 December 1993; also available as ANSI/ASTM D                           
 4007, API Stock No. H30203.                                            
MPMS, Chapter 10, Section 4, Determination of  Sec.  250.182 (a)(3),    
 Sediment and Water in Crude Oil by the         (l)(4).                 
 Centrifuge Method (Field Procedure), Second                            
 Edition, May 1988; also available as ANSI/                             
 ASTM D 96, API Stock No. H30204.                                       

[[Page 26370]]

                                                                        
MPMS, Chapter 11.1, Volume Correction          Sec.  250.182 (a)(3),    
 Factors, Volume 1, Table 5A--Generalized       (g)(3), (l)(4).         
 Crude Oils and JP-4 Correction of Observed                             
 API Gravity to API Gravity at 60 deg.F, and                            
 Table 6A--Generalized Crude Oils and JP-4                              
 Correction of Observed API Gravity to API                              
 Gravity at 60 deg.F, First Edition, August                             
 1980, reaffirmed October 1993; also                                    
 available as ANSI/ASTM D 1250, API Stock No.                           
 H27000.                                                                
MPMS, Chapter 11.2.1, Compressibility Factors  Sec.  250.182(a)(3),(g)(4
 for Hydrocarbons: 0-90 deg. API Gravity        ).                      
 Range, First Edition, August 1984,                                     
 reaffirmed May 1996, API Stock No. H27300.                             
MPMS, Chapter 11.2.2, Compressibility Factors  Sec.  250.182(a)(3),(g)(4
 for Hydrocarbons: 0.350-0.637 Relative         ).                      
 Density (60 deg.F/60 deg.F) and -50 deg.F to                           
 140 deg.F Metering Temperature, Second                                 
 Edition, October 1986, reaffirmed October                              
 1992; also available as Gas Processors                                 
 Association (GPA) 8286-86, API Stock No.                               
 H27307.                                                                
MPMS, Chapter 11, Physical Properties Data,    Sec.  250.182(a)(3).     
 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.                          
MPMS, Chapter 11.2.3, Water Calibration of     Sec.  250.182(f)(1).     
 Volumetric Provers, First Edition, August                              
 1984, reaffirmed, May 1996, API Stock No.                              
 H27310.                                                                
MPMS, Chapter 12, Calculation of Petroleum     Sec.  250.182(a)(3),     
 Quantities, Section 2, Calculation of          (g)(1), (g)(2)          
 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.                                                                
MPMS, Chapter 14, Natural Gas Fluids           Sec.  250.183(b)(2).     
 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.                                                                
MPMS, Chapter 14, Section 3, Part 2,           Sec.  250.183(b)(2).     
 Specification and Installation Requirements,                           
 Third Edition, February 1991; also available                           
 as ANSI/API 2530, Part 2, 1991, API Stock                              
 No. H30351.                                                            
MPMS, Chapter 14, Section 3, Part 3, Natural   Sec.  250.183(b)(2).     
 Gas Applications, Third Edition, August                                
 1992; also available as ANSI/API 2530, Part                            
 3, API Stock No. H30353.                                               
MPMS, Chapter 14, Section 5, Calculation of    Sec.  250.183(b)(2).     
 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.                                                        
MPMS, Chapter 14, Section 6, Continuous        Sec.  250.183(b)(2).     
 Density Measurement, Second Edition, April                             
 1991, API Stock No. H30346.                                            
MPMS, Chapter 14, Section 8, Liquefied         Sec.  250.183(b)(2).     
 Petroleum Gas Measurement, First Edition,                              
 February 1983, reaffirmed May 1996, API                                
 Stock No. H30348.                                                      
MPMS, Chapter 20, Section 1, Allocation        Sec.  250.182(k)(1).     
 Measurement, First Edition, September 1993,                            
 API Stock No. H30701.                                                  
MPMS, Chapter 21, Section 1, Electronic Gas    Sec.  250.183(b)(4).     
 Measurement, First Edition, September 1993,                            
 API Stock No. H30730.                                                  
ASTM Standard C33-93, Standard Specification   Sec.  250.138(b)(4)(i).  
 for Concrete Aggregates including                                      
 Nonmandatory Appendix.                                                 
ASTM Standard C94-96, Standard Specification   Sec.  250.138(e)(2)(i).  
 for Ready-Mixed Concrete.                                              
ASTM Standard C150-95a, Standard               Sec.  250.138(b)(2)(i).  
 Specification for Portland Cement.                                     
ASTM Standard C330-89, Standard Specification  Sec.  250.138(b)(4)(i).  
 for Lightweight Aggregates for Structural                              
 Concrete.                                                              
ASTM Standard C595-94, Standard Specification  Sec.  250.138(b)(2)(i).  
 for Blended Hydraulic Cements.                                         
D1.1-96, Structural Welding Code--Steel,       Sec.  250.137(b)(1)(i).  
 1996, including Commentary.                                            
DI.4-79, Structural Welding Code--Reinforcing  Sec.  250.138 (e)(3)(ii).
 Steel, 1979.                                                           
NACE Standard MR-01-75-96, Sulfide Stress      Sec.  250.67 (p)(2).     
 Cracking Resistant Metallic Materials for                              
 Oil Field Equipment, January 1996.                                     
NACE Standard RP 0176-94, Standard             Sec.  250.137(d).        
 Recommended Practice, Corrosion Control of                             
 Steel Fixed Offshore Platforms Associated                              
 with Petroleum Production.                                             
------------------------------------------------------------------------

    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


Sec. 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     Sec.  250.182(a).        
 liquid hydrocarbons?.                                                  
2. What are the requirements for liquid        Sec.  250.182(b).        
 hydrocarbon royalty meters?.                                           
3. What are the requirements for run tickets?  Sec.  250.182(c).        
4. What are the requirements for liquid        Sec.  250.182(d).        
 hydrocarbon royalty meter provings?.                                   
5. What are the requirements for calibrating   Sec.  250.182(e).        
 a master meter used in royalty meter                                   
 provings?.                                                             
6. What are the requirements for calibrating   Sec.  250.182(f).        
 mechanical-displacement provers and tank                               
 provers?.                                                              

[[Page 26371]]

                                                                        
7. What correction factors must I use when     Sec.  250.182(g).        
 proving meters with a mechanical                                       
 displacement prover, tank prover, or master                            
 meter?.                                                                
8. What are the requirements for establishing  Sec.  250.182(h).        
 and applying operating meter factors for                               
 liquid hydrocarbons?.                                                  
9. Under what circumstances does a liquid      Sec.  250.182(i).        
 hydrocarbon royalty meter need to be taken                             
 out of service, and what must I do?.                                   
10. How must I correct gross liquid            Sec.  250.182(j).        
 hydrocarbon volumes to standard conditions?.                           
11. What are the requirements for liquid       Sec.  250.182(k).        
 hydrocarbon allocation meters?.                                        
12. What are the requirements for royalty and  Sec.  250.182(l).        
 inventory tank facilities ?.                                           
13. To which meters do MMS requirements for    Sec.  250.183(a).        
 gas measurement apply?.                                                
14. What are the requirements for measuring    Sec.  250.183(b).        
 gas?.                                                                  
15. What are the requirements for gas meter    Sec.  250.183(c).        
 calibrations?.                                                         
16. What must I do if a gas meter is out of    Sec.  250.183(d).        
 calibration or malfunctioning?.                                        
17. What are the requirements when natural     Sec.  250.183(e).        
 gas from a Federal lease on the OCS is                                 
 transferred to a gas plant before royalty                              
 determination?.                                                        
18. What are the requirements for measuring    Sec.  250.183(f).        
 gas lost or used on a lease?.                                          
19. What are the requirements for the surface  Sec.  250.184(a).        
 commingling of production?.                                            
20. What are the requirements for a periodic   Sec.  250.184(b).        
 well test used for allocation?.                                        
21. What are the requirements for site         Sec.  250.185(a).        
 security?.                                                             
22. What are the requirements for using        Sec.  250.185(b).        
 seals?.                                                                
------------------------------------------------------------------------

Sec. 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 
deg.F) to 60.5 degrees Fahrenheit (60.5  deg.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 deg. 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 deg. F.
    You or your--the lessee or the operator or other lessees' 
representative engaged in operations in the Outer Continental Shelf 
(OCS).


Sec. 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

[[Page 26372]]

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 MMS-approved 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 vapor-tight 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 
mechanical-displacement 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

[[Page 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.


Sec. 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 deg. 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

[[Page 26374]]

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.


Sec. 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.


Sec. 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, drain-line 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