[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.
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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.
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Have the OMB
The information collections in approval and
number
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Parts 202 and 216........................ 1010-0040 Are not modified by this rule.
Subpart L of part 250.................... 1010-0051 Are modified by this rule.
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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
