[Federal Register Volume 62, Number 38 (Wednesday, February 26, 1997)]
[Proposed Rules]
[Pages 8665-8671]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 97-4534]


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DEPARTMENT OF THE INTERIOR
Minerals Management Service

30 CFR Part 250

RIN 1010-AB97


Oil and Gas Production Measurement, Surface Commingling, and 
Security

AGENCY: Minerals Management Service (MMS), Interior.

ACTION: Proposed rule.

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SUMMARY: This proposed rule would amend MMS regulations governing oil 
and gas operations in the Outer Continental Shelf (OCS) to update 
production measurement and surface commingling requirements. The MMS 
needs this rule to help ensure that gas produced in the OCS is 
accurately measured and reported.

DATES: MMS will consider all comments received by May 27, 1997. We will 
begin reviewing comments at that time and may not fully consider 
comments we receive after May 27, 1997.

ADDRESSES: Mail or hand-carry comments to the Department of the 
Interior; Minerals Management Service; Mail Stop 4700; 381 Elden 
Street; Herndon, Virginia 20170-4817; Attention: Rules Processing Team.

FOR FURTHER INFORMATION CONTACT:
Sharon Buffington, Engineering and Research Branch, at (703) 787-1147.

SUPPLEMENTARY INFORMATION: Pipeline and price deregulation and open 
access to pipelines that occurred in the late 1980's spawned a 
restructuring of OCS pipeline system operations. Pipeline companies 
traditionally were merchants buying and selling gas under long-term 
contracts to only a few well established customers. Under the Federal 
Energy Regulatory Commission Order 636, pipeline companies operate as 
common carriers involved in transportation services to a broad spectrum 
of gas producers, end users, and transportation brokers. Also, the OCS 
pipeline systems have hundreds of short-term, limited volume contracts, 
many of which require daily accounting and balance controls.

[[Page 8666]]

    Because of the restructuring and complexity in pipeline operating 
systems and the increasing use and value of natural gas, the accuracy 
and reliability of meters have become even more important to ensuring 
product accountability and fiscal responsibility. Therefore, industry 
has initiated production measurement research that resulted in more 
precise metering and data collection equipment.
    Most of the production in the OCS is natural gas and a 1 percent 
measurement or reporting uncertainty could result in royalty revenue 
variations of $15 million per year. MMS is responsible for ensuring 
accurate production measurement and reporting.
    The gas measurement and commingling regulations now in effect were 
based on conditions before deregulation and before the industry began 
to apply the results of research efforts. Therefore, MMS is proposing 
to amend the production measurement and commingling regulations. The 
regulatory revisions proposed in this rule would:
     Reflect current industry technology,
     Form the basis for a gas verification system (GVS),
     Require tracking of gas lost or used on the lease, and
     Clarify the restrictions on surface commingling.
    The liquid measurement regulations of 1988 already give the 
guidance for our liquid verification system. Therefore, MMS is not 
proposing technical changes to liquid measurement; we are only 
clarifying the language.
    On June 23, 1994, a meeting was held at the Department of the 
Interior (DOI) in Washington, D.C., to introduce the oil and gas 
industry to the principles of this rulemaking and the proposed GVS. The 
participants generally agreed that the regulations on production 
measurement should be updated to include current industry standards. 
The main items discussed at the meeting are as follows:
    1. If MMS verifies gas production and also conducts audits, it 
appears that industry is under a double jeopardy. Currently, MMS only 
audits some OCS gas production. MMS is proposing to supplement the 
audits by implementing a limited gas verification program that will 
create a system to quickly check submitted gas production volumes with 
gas volume statements. MMS will coordinate gas verification and the 
royalty audit programs.
    2. Why does MMS want daily production data on the gas volume 
statements to verify production reported monthly? While daily 
production data is easier to obtain from electronically measured data 
than from chart recorders, it appears that meter owners provide gas 
producers (lessees) a daily breakout of gas production once a month. 
Daily production data is the best data to use to verify gas production.
    3. How will MMS verify gas that is processed before royalty is 
calculated? MMS will use the monthly statement that gas plant managers 
supply to producers instead of the gas volume statement. However, if 
these statements are not prepared on a daily basis for the month, MMS 
may ask for additional data from the lessee to verify production.
    4. MMS is seeking comments concerning whether you receive monthly 
gas measurement statements from meter owners that show a daily summary 
of volumes and quality. If you do not receive the statements, please 
list how you audit the production records.
    5. MMS is seeking comments on the applicable industry standards and 
practices that we incorporate and exclude. This proposed rule would 
require that lessees follow the standards listed in 30 CFR 250.1, 
Documents Incorporated by Reference. MMS published that final rule on 
November 26, 1996, (61 FR 60019).
    6. This proposed rule would require seals only on liquid 
hydrocarbon royalty installations. However, MMS may also require seals 
on gas installations in the final rule. Please comment on this 
proposal.
    7. MMS is also seeking comments on the type of records you keep for 
gas used on the lease, how you record volumes and quality, and how you 
measure or estimate volumes and quality.

Executive Order (E.O.) 12866

    DOI has certified that this proposed rule is not a significant rule 
under E.O. 12866.

E.O. 12988

    DOI has certified to the Office of Management and Budget (OMB) that 
the rule meets the applicable reform standards provided in sections 
3(a) and 3(b)(2) of E.O. 12988.

Unfunded Mandates Reform Act of 1995

    DOI has determined and certifies according to the Unfunded Mandates 
Reform Act, 2 U.S.C. 1502 et seq., that this rule will not impose a 
cost of $100 million or more in any year on State, local, and tribal 
governments, or the private sector.

Regulatory Flexibility Act

    The DOI has determined that this proposed rule will not have a 
significant economic effect on a substantial number of small entities.

Paperwork Reduction Act

    This proposed rule contains a collection of information which has 
been submitted to OMB for review and approval under section 3507(d) of 
the Paperwork Reduction Act of 1995. As part of our continuing effort 
to reduce paperwork and respondent burden, MMS invites the public and 
other Federal agencies to comment on any aspect of the reporting 
burden. Submit your comments to the Office of Information and 
Regulatory Affairs; OMB; Attention Desk Officer for the Department of 
the Interior, 725 17th Street NW, Washington, D.C. 20503 (OMB control 
number 1010-0051). Send a copy of your comments to the Chief, 
Engineering and Standards Branch; Mail Stop 4700; Minerals Management 
Service; 381 Elden Street; Herndon, Virginia 20170-4817. You may obtain 
a copy of the proposed collection of information by contacting the 
Bureau's Information Collection Clearance Officer at (703) 787-1242.
    OMB may make a decision to approve or disapprove this collection of 
information after 30 days from receipt of our request. Therefore, your 
comments are best assured of being considered by OMB if OMB receives 
them within that time period. However, MMS will consider all comments 
received during the comment period for this notice of proposed 
rulemaking.
    The title of this collection of information is ``30 CFR 250, 
Subpart L, Oil and Gas Production Measurement, Surface Commingling, and 
Security.'' OMB previously approved it under OMB control number 1010-
0051.
    The collection of information consists of oil run tickets; proving 
and calibrations reports; measuring liquid hydrocarbons and gas; 
applications for surface commingling, and various recordkeeping 
requirements. The proposed rule would delete some recordkeeping and 
reporting requirements. it would add the following when required by the 
Regional Supervisor:
     Gas volume statements,
     Production quality data, and
     Data concerning gas lost or used on the lease.
    MMS would use the information to verify production measurements.
    Respondents are Federal OCS oil, gas, and sulphur lessees. MMS will 
receive approximately 2,300 new responses

[[Page 8667]]

each year. The frequency of submission varies.
    MMS estimates the additional annual reporting burden as a result of 
this rule would be approximately 192 hours (.08 hour per response). We 
estimate the total annual burden to be 2,615 reporting hours and 2,429 
recordkeeping hours. Based on $35 per hour, the total burden hour cost 
to respondents is estimated to be $176,540.
    In calculating the burden, MMS assumed that respondents perform 
many of the requirements and maintain records in the normal course of 
their activities. MMS considers these to be usual and customary and did 
not include them in the burden estimates. Commenters are invited to 
provide information if they disagree with this assumption and they 
should tell us what are the burden hours and costs imposed by this 
collection of information.
    MMS will summarize written responses to this notice and address 
them in the final rule. All comments will become a matter of public 
record.
    1. MMS specifically solicits comments on the following questions:
    (a) Is the proposed collection of information necessary for the 
proper performance of MMS's functions, and will it be useful?
    (b) Are the estimates of the burden hours of the proposed 
collection reasonable?
    (c) Do you have any suggestions that would enhance the quality, 
clarity, or usefulness of the information to be collected?
    (d) Is there a way to minimize the information collection burden on 
those who are to respond, including through the use of appropriate 
automated electronic, mechanical, or other forms of information 
technology?
    2. In addition, the Paperwork Reduction Act of 1995 requires 
agencies to estimate the total annual cost burden to respondents or 
recordkeepers resulting from the collection of information. MMS needs 
your comments on this item. Your response should split the cost 
estimate into two components:
    (a) Total capital and startup cost and
    (b) Annual operation, maintenance, and purchase of services.
    Your estimates should consider the costs to generate, maintain, and 
disclose or provide the information. You should describe the methods 
you use to estimate major cost factors, including system and technology 
acquisition, expected useful life of capital equipment, discount 
rate(s), and the period over which you incur costs. Capital and startup 
costs include, among other items, computers and software you purchase 
to prepare for collecting information; monitoring, sampling, drilling, 
and testing equipment; and record storage facilities. Generally, your 
estimates should not include equipment or services purchased: Before 
October 1, 1995; to comply with requirements not associated with the 
information collection; for reasons other than to provide information 
or keep records for the Government; or as part of customary and usual 
business or private practices.
    The Paperwork Reduction Act of 1995 provides that an agency may not 
conduct or sponsor, and a person is not required to respond to, a 
collection of information unless it displays a currently valid OMB 
control number.

Takings Implication Assessment

    DOI certifies that the proposed rule does not represent a 
governmental action capable of interference with constitutionally 
protected property rights. Thus, a Takings Implication Assessment need 
not be prepared pursuant to E.O. 12630, Government Action and 
Interference with Constitutionally Protected Property Rights.

National Environmental Policy Act

    DOI determined that this rulemaking does not constitute a major 
Federal action significantly affecting quality of the human 
environment; therefore, an Environmental Impact Statement is not 
required.

List of Subjects in 30 CFR Part 250

    Continental shelf, Environmental impact statements, Environmental 
protection, Government contracts, Incorporation by reference, 
Investigations, Mineral royalties, Oil and gas development and 
production, Oil and gas exploration, Oil and gas reserves, Penalties, 
Pipelines, Natural gas, Petroleum, Public lands--mineral resources, 
Public lands--rights-of-way, Reporting and recordkeeping requirements, 
Sulphur development and production, Sulphur exploration, Surety bonds.

    Dated: December 30, 1996.
Bob Armstrong,
Assistant Secretary, Land and Minerals Management.

    For the reasons in the preamble, the Minerals Management Service 
(MMS) proposes to amend 30 CFR part 250 as follows:

PART 250--OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER 
CONTINENTAL SHELF

    1. The authority citation for part 250 continues to read as 
follows:

    Authority: 43 U.S.C. 1334.

    2. Subpart L is revised to read as follows:

Subpart L--Oil and Gas Production Measurement, Surface Commingling, and 
Security

Sec.
250.180  Question index table.
250.181  Definitions for Subpart L.
250.182  Liquid Hydrocarbon measurement.
250.183  Gas measurement.
250.184  Surface commingling.
250.185  Site security.
250.186  Measuring gas lost or used on a lease.

Subpart L--Oil and Gas Production Measurement, Surface Commingling, 
and Security


Sec. 250.180  Question Index Table

    The table in this section lists questions concerning Oil and Gas 
Production Measurement, Surface Commingling, and Security and the 
location of the answers.

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          Frequently asked questions                  CFR citation      
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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 a master       Sec.  250.182 (e).      
 meter and its calibration?.                                            
6. What are the requirements for calibrating    Sec.  250.182 (f).      
 mechanical-displacement provers and tank                               
 provers?.                                                              
7. What correction factors must a lessee        Sec.  250.182 (g).      
 account for when calibrating meters with a                             
 mechanical displacement prover, tank provers                           
 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 MMS consider   Sec.  250.182 (i).      
 that a liquid hydrocarbon royalty meter                                
 failed and what must a lessee do?.                                     

[[Page 8668]]

                                                                        
10. How must a lessee correct gross liquid      Sec.  250.182 (j).      
 hydrocarbon volumes measured under                                     
 nonstandard conditions?.                                               
11. What are the requirements for liquid        Sec.  250.182 (k).      
 hydrocarbon allocation meters?.                                        
12. What are the requirements for tank          Sec.  250.182 (l).      
 facilities designated as a royalty point?.                             
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 a lessee do if a gas meter is     Sec.  250.183 (d).      
 malfunctioning?.                                                       
17. What are the requirements when natural gas  Sec.  250.183 (e).      
 from a Federal lease is delivered to a gas                             
 plant?.                                                                
18. What are the requirements when commingling  Sec.  250.184 (a).      
 production at the surface?.                                            
19. What are the requirements for a well test   Sec.  250.184 (b).      
 used for allocation?.                                                  
20. What are the requirements for site          Sec.  250.185 (a).      
 security?.                                                             
21. What are the requirements for using seals?  Sec.  250.185 (b).      
22. What are the requirements for measuring     Sec.  250.186.          
 gas lost or used on a lease?.                                          
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Sec. 250.181  Definitions for subpart L.

    Terms used in Subpart L have the following meaning:
    Allocation meter means a meter whose volume measurement 
substantiates which portion of the volume measured by a royalty meter 
is attributable to a particular lease, unit, well, or other measurement 
point.
    API MPMS means the American Petroleum Institute's Manual of 
Petroleum Measurement Standards.
    British Thermal Unit (Btu) means the amount of heat needed to raise 
the temperature of one pound of water by 1 degree Fahrenheit (1 deg.F) 
at standard atmospheric pressure.
    Calibration means the adjustment or standardization of a measuring 
instrument to yield precise data.
    Fractional Analysis means separating mixtures into identifiable 
components expressed in mole percent.
    Gas meter means an approved meter that measures natural gas and 
upon which MMS bases royalty and/or allocation volumes.
    Gas processing plant means an installation for processing natural 
gas to remove impurities and recover natural gas liquids (NGL's) and 
other products. The NGL's are reported as the sum of the products 
(ethane, propane, butane, and natural gasoline) on the report of sales 
and royalty remittance. Products like nitrogen, sulphur, carbon dioxide 
and helium are reported separately.
    Gas processing plant statement means a monthly statement showing 
the volume and quality of the inlet gas stream and the plant products 
recovered during the period, volume of deductible plant fuel, and the 
allocation of plant products to the sources of the inlet stream.
    Gas royalty meter malfunction means an error in the gas measurement 
device that exceeds manufacturers specifications.
    Gas volume statement means a document prepared by the owner of a 
gas meter that identifies the volume of natural gas measured by the 
meter. The statement contains information such as pressure base, 
temperature base, and volumetric data in a thousand cubic feet (Mcf) 
and quality data in gross Btu's per cubic foot.
    Liquid hydrocarbons (free liquids) mean a mixture of hydrocarbons 
produced in liquid form after passing through surface separating 
facilities.
    Malfunction factor means a liquid hydrocarbon royalty meter factor 
that differs from the previous meter factor by an amount greater than 
0.0025.
    Natural gas means all components of a whole natural gas stream 
which pass a meter in vapor phase at the measurement point.
    Natural gas liquids (NGL's) mean components of natural gas that are 
liquefied from the whole gas stream and extracted in gas processing 
plants.
    Operating meter means a meter that is used for measurement at any 
time during the month. A meter must be proved or calibrated only if it 
is an operating meter.
    Pressure base means the pressure at which gas volumes are reported. 
The standard pressure base for converting measured volumes to standard 
volumes is 14.73 pounds per square inch absolute (psia).
    Prove means to determine the accuracy of a meter, usually by 
running a known quantity (or quantities) of hydrocarbon through the 
meter at a known temperature and pressure while recording the meter 
volume registration.
    Retrograde condensate means liquid hydrocarbons that drop out of 
the separated gas stream at any point prior to entering a gas 
processing plant, but after the facility measurement point.
    Royalty meter means an approved meter that measures natural gas or 
liquid hydrocarbons and upon which MMS bases royalty volumes.
    Run ticket means the invoice for liquid hydrocarbons measured at a 
royalty point.
    Sales meter means a meter at which custody transfer takes place 
(not necessarily a royalty meter).
    Seal means a device or approved method used to prevent tampering 
with measurement facility components.
    Standard conditions means 14.73 pounds per square inch absolute 
(psia) and 60 deg. F.
    Surface commingling means the surface mixing of production from two 
or more leases or units prior to measurement for royalty purposes.
    Temperature base means the temperature at which gas volumes are 
reported. The standard temperature base for use in converting measured 
volumes to standard volumes is 60 deg. F.
    You or your means the lessee or contractor engaged in operations in 
the Outer Continental Shelf (OCS).


Sec. 250.182  Liquid hydrocarbon measurement.

    (a) What are the requirements for measuring liquid hydrocarbons? 
Lessees must:
    (1) Commence liquid hydrocarbon production or make changes to 
previously approved measurement procedures only after the Regional 
Supervisor has approved the liquid hydrocarbon application or changes 
to an existing approval;
    (2) Use measurement equipment that will accurately measure the 
liquid hydrocarbons produced from a lease or unit;
    (3) Use procedures and correction factors according to the 
applicable chapters of the API MPMS as referenced in 30 CFR 250.1 when 
obtaining net standard volume and associated measurement parameters; 
and
    (4) When requested by the Regional Supervisor, determine the 
retrograde condensate volume and allocate it back to the individual 
leases and/or units and wells.
    (b) What are the requirements for liquid hydrocarbon royalty 
meters? Lessees must:
    (1) Ensure that the royalty meter facilities include the following 
components (or other MMS-approved

[[Page 8669]]

components) which must be compatible with their connected systems:
    (i) A positive-displacement meter equipped with a nonreset 
totalizer;
    (ii) A mechanical displacement prover, a master meter, a calibrated 
tank prover;
    (iii) A proportional-to-flow sampling device pulsed by the meter 
output; and
    (iv) A temperature measurement or temperature compensation device.
    (2) Ensure that the royalty meter facilities accomplish the 
following:
    (i) Prevent flow reversal through the meter;
    (ii) Protect meters subjected to pressure pulsations or surges;
    (iii) Prevent the meter from shock pressures greater than the 
maximum working pressure; and
    (iv) Prevent meter bypassing.
    (3) Maintain royalty meter facilities to ensure the following:
    (i) Meters operate within the gravity range specified by the 
manufacturer;
    (ii) Meters operate within the manufacturer's specifications for 
maximum and minimum flow rate for linear accuracy; and
    (iii) Meters are reproven when changes in metering conditions 
affect the meters performance such as changes in pressure, temperature, 
density (water content), viscosity, pressure, and flow rate.
    (4) Ensure that sampling devices conform to the following:
    (i) The sampling point is in the flowstream immediately upstream or 
downstream of the meter or divert valve;
    (ii) The sample container is vapor-tight and includes a mixing 
device to allow complete mixing of the sample before removal from the 
container; and
    (iii) The sample probe is in the center of the flow piping in a 
vertical run and is located at least three pipe diameters downstream of 
any pipe fitting within a region of turbulent flow.
    (c) What are the requirements for run tickets? Lessees must:
    (1) Send all run tickets pulled and/or completed to the Regional 
Supervisor within 15 days following the end of the month;
    (2) Pull a run ticket when establishing the monthly meter factor or 
a malfunction meter factor. Send the Regional Supervisor a copy of this 
run ticket; and
    (3) Ensure that run tickets clearly identify all observed data, all 
correction factors not included in the meter factor, the net standard 
volume, and all calculations and factors.
    (d) What are the requirements for liquid hydrocarbon royalty meter 
provings? Lessees must:
    (1) Permit MMS representatives to witness regularly scheduled 
provings or any proving requested by the Regional Supervisor;
    (2) Ensure that the integrity of the prover calibration is 
traceable to test measures certified by the National Institute of 
Standards and Technology;
    (3) Prove each operating royalty meter to determine the meter 
factor during each month but the time between meter factor 
determinations must not exceed 42 days; and
    (4) Submit copies of all meter proving reports for royalty meters 
to the Regional Supervisor monthly within 15 days after the end of the 
month.
    (e) What are the requirements for a master meter and its 
calibration? Lessees must:
    (1) Calibrate the master meter to obtain a meter factor before 
using it to determine operating meter factors;
    (2) Use a fluid of similar gravity, viscosity, temperature, and 
flow rate as the liquid hydrocarbons that flow through the operating 
meter to calibrate the master meter;
    (3) Calibrate the master meter during each month but the time 
between calibrations must not exceed 42 days;
    (4) Calibrate the master meter by recording runs until the results 
of two consecutive runs (if a tank prover is used) or five out of six 
consecutive runs (if a mechanical-displacement prover is used) produce 
maximum meter factor differences of 0.0002. Lessees must use the 
average of the two (or the five) runs that produced acceptable results 
to compute the master meter factor; and
    (5) Install the master meter upstream of any back-pressure or 
reverse flow check valves associated with the operating meter. However, 
you may install master meters either upstream or downstream of the 
operating meter.
    (6) Keep a copy of the master meter proving report at your field 
location for 2 years.
    (f) What are the requirements for calibrating mechanical-
displacement provers and tank provers? Lessees must:
    (1) Calibrate mechanical-displacement provers and tank provers at 
least once every 5 years according to the API MPMS as referenced in 30 
CFR 250.1; and
    (2) Submit a copy of each calibration report to the Regional 
Supervisor within 15 days after the calibration.
    (g) What correction factors must a lessee account for when 
calibrating meters with a mechanical-displacement prover, tank prover, 
or master meter? Use the following correction factors from the API MPMS 
as referenced in 30 CFR 250.1:
    (1) The change in prover volume due to pressure in the steel pipe 
(Cps);
    (2) The change in volume of the test liquid with the change in 
temperature (Ctl);
    (3) The change in prover volume due to the change in temperature 
(Cts); and
    (4) The change in volume of the test liquid with the change in 
pressure (Cpl).
    (h) What are the requirements for establishing and applying 
operating meter factors for liquid hydrocarbons?
    (1) If you use a mechanical-displacement prover, you must record 
proof runs until five out of six consecutive runs produce a maximum 
difference between individual runs of .0005. You must use the average 
of the five runs to compute the meter factor.
    (2) If you use a master meter, you must record proof runs until 
three consecutive runs produce a maximum total meter factor difference 
of 0.0005. The volume of each run must be at least 10 percent of the 
hourly rated capacity of the operating meter. You must use the average 
of the three runs to compute the meter factor.
    (3) If you use a tank prover, you must record proof funs until two 
consecutive runs produce a maximum meter factor difference of .05 
percent of the tank prover volume. You must use the average of the two 
consecutive runs to compute the meter factor.
    (4) You must apply meter factors that are within tolerance starting 
with the date of the proving.
    (i) Under what circumstances does MMS consider that a liquid 
hydrocarbon royalty meter failed and what must a lessee do?
    (1) If the difference between the meter factor and the previous 
factor exceeds 0.0025 it is a malfunction factor and lessees must do 
the following:
    (i) Remove the meter from service and check it for damage and/or 
wear;
    (ii) Adjust it and/or repair it, and reprove it;
    (iii) Apply the average of the malfunction factor and the previous 
factor to the production measured through the meter between the date of 
the previous factor and the date of the malfunction factor; and
    (iv) Show all appropriate remarks regarding subsequent repairs and/
or adjustments on the proving report.
    (2) If a meter fails to register production the lessee must do the 
following:
    (i) Remove the meter from service, repair and reprove it;
    (ii) Apply the previous meter factor to the production run between 
the date of that factor and the date of the failure; and
    (iii) Estimate unregistered production by the best possible means 
and report it as estimated production on the proving report.

[[Page 8670]]

    (3) If the results of a royalty meter proving exceed the run 
tolerance criteria and all measures excluding the adjustment and/or 
repair of the meter can't bring results within tolerance the lessees 
must:
    (i) Establish a factor using proving results made before any 
adjustment and/or repair of the meter; and
    (ii) Treat the established factor like a malfunction factor [See 
paragraph (i)(1) of this section].
    (j) How must a lessee correct gross liquid hydrocarbon volumes 
measured under nonstandard condition?
    (1) Calculate Cpl factors into the meter factor or list and apply 
them on the appropriate run ticket.
    (2) List the Ctl factors on the appropriate run ticket when the 
meter is not automatically temperature compensated.
    (k) What are the requirements for liquid hydrocarbon allocation 
meters? Lessees must:
    (1) Take samples continuously or daily;
    (2) For turbine meters, take the sample proportional to the flow;
    (3) Prove allocation meters monthly if they measure 50 or more 
barrels of oil per day per meter; or
    (4) Prove allocation meters quarterly if they measure less than 50 
barrels of oil per day per meter;
    (5) Keep a copy of the proving reports at the field location for 2 
years;
    (6) Adjust and reprove the meter if a meter factor differs from the 
previous meter factor by more than 2 percent and less than 7 percent;
    (7) For turbine meters, inspect the meter if a factor differs from 
the previous meter factor by more than 2 percent and less than 7 
percent; and
    (8) Repair or replace and reprove the meter if a meter factor 
differs from the previous meter factor by 7 percent or more.
    (l) What are the requirements for tank facilities designated as a 
royalty point? Lessees must:
    (1) Equip the tank with a vapor-tight thief hatch, a vent-line 
valve, and a fill line designed to minimize free fall and splashing;
    (2) Submit a complete set of calibration charts (tank tables) to 
the Regional Supervisor before using the tank for measuring sales;
    (3) Obtain the volume and other measurement parameters by using 
correction factors and procedures in the API MPMS as referenced in 30 
CFR 250.1; and
    (4) Submit a copy of each run ticket written from tank gaugings to 
the Regional Supervisor within 15 days after the end of the month.


Sec. 250.183  Gas measurement

    (a) To which meters do MMS requirements for gas measurement apply? 
All OCS gas royalty and allocation meters.
    (b) What are the requirements for measuring gas? Lessees must:
    (1) Commence gas production or make changes to previously approved 
measurement procedures only after the Regional Supervisor has approved 
the gas measurement application or changes to an existing approval.
    (2) Design, install, use, maintain, and test measurement equipment 
to ensure accurate and complete measurement. You must follow the 
recommendations in API MPMS (referenced in 30 CFR 250.1).
    (3) Ensure that the measurement components are compatible with 
their connected systems.
    (4) Equip the meter with a chart or electronic data recorder. 
Electronic data recorders must be capable of displaying real-time data 
during MMS inspections.
    (5) Use continuous on-line chromatographic analyzers or sampling 
ports upstream or downstream of the meter. Take a sample at least once 
each calendar month but intervals must not exceed 42 days.
    (6) Ensure that standard conditions for reporting gross heating 
value are at a base temperature of 60 deg. F and at a base pressure of 
14.73 pounds per square inch absolute (psia).
    (7) When requested by the Regional Supervisor, submit gas volume 
statements for each requested month's gas sales. Show whether gas 
volumes and gross Btu heating value are reported at saturated or 
unsaturated conditions.
    (8) When requested by the Regional Supervisor, provide any data 
necessary for gas volume and quality calculations.
    (c) What are the requirements for gas meter calibrations? Lessees 
must:
    (1) Calibrate meters monthly but not exceed 42 days between 
calibrations.
    (2) Following a meter calibration, adjust the meter equipment (if 
necessary) by using the manufacturer's specifications.
    (3) For positive displacement or turbine meters, conduct 
calibrations at the average hourly rate of flow since the last 
calibration.
    (4) Retain calibration test data at the field location for 2 years 
and send the data to the Regional Supervisor upon request.
    (5) Permit MMS representatives to witness regularly scheduled 
calibrations and any calibration requested by the Regional Supervisor.
    (d) What must a lessee do if a gas meter is malfunctioning?
    (1) If a gas meter is malfunctioning, adjust the meter to function 
properly or remove it from service and replace it.
    (2) Correct the volumes to the last acceptable calibration as 
follows:
    (i) If the duration of the error can be determined, calculate the 
volume adjustment for that period. The MMS does not require retroactive 
volume adjustments for allocation beyond 21 days; or
    (ii) If the duration of the error can't be determined, apply the 
volume adjustment to one-half of the time elapsed since the last 
calibration or 21 days, whichever is less.
    (e) What are the requirements when natural gas from a Federal lease 
is delivered to a gas plant?
    (1) Lessees must provide the following to the Regional Supervisor 
upon request:
    (i) The gas processing plant statement;
    (ii) A gas volume statement for each of the lessee's meter facility 
sites that contribute natural gas to the processing plant; and
    (iii) Composite fractional analyses and gross heating values.
    (2) MMS may inspect the measurement and sampling equipment of 
natural gas processing plants that process Federal production.


Sec. 250.184  Surface commingling.

    (a) What are the requirements when commingling production at the 
surface? Lessees must:
    (1) Commence commingling of production only after the Regional 
Supervisor has approved the commingling and the method of measurement.
    (2) Submit an application containing the following information:
    (i) The method of allocation measurement and processing, if 
applicable;
    (ii) The manner of entry into the commingled system; and
    (iii) Any other information that the Regional Supervisor requests.
    (3) Submit any changes to an approved commingling application to 
the Regional Supervisor for approval.
    (4) Upon the request of the Regional Supervisor, lessees who 
deliver natural gas into a commingled system of both Federal and non-
Federal production must provide volumetric and fractional analyses on 
the non-Federal gas through the designated system operator. If a 
lessees fails to provide that data, MMS will not permit the lessee to 
deliver Federal gas into the commingled system.
    (b) What are the requirements for a well test used for allocation? 
Lessees must:

[[Page 8671]]

    (1) Conduct a well test at least once every 2 months unless the 
Regional Supervisor approved a different frequency;
    (2) Follow the well test procedures in Sec. 250.173; 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? Lessees must:
    (1) Protect Federal production against production loss or theft;
    (2) Post a sign at each storage tank that MMS uses to determine 
royalty. The sign must contain the name of the facility operator, the 
size of the tank, and the tank number;
    (3) Not bypass MMS-approved liquid hydrocarbon royalty meters and 
tanks; and
    (4) Report the following to the Regional Supervisor as soon as 
possible, but no later than the next business day after discovery:
    (i) Theft or mishandling of production;
    (ii) Tampering or bypassing of meter or prover devices; and
    (iii) Falsifying production measurements.
    (b) What are the requirements for using seals? Lessees must:
    (1) Seal the following components of liquid hydrocarbon royalty 
installations to ensure that tampering cannot occur without destroying 
the seal:
    (i) Meter stack component connections from the base of the stack to 
the register;
    (ii) Sampling systems including packing device, fittings, chains, 
sight glass, and container lid;
    (iii) Temperature and gravity compensation device components;
    (iv) All valves on lines leaving an oil storage tank including 
load-out line valves, drain-line valves, and connection-line valves 
between royalty and non-royalty tanks; and
    (v) Any additional components required by the Regional Supervisor.
    (2) Number and track the seals and keep the record at the field 
location for 2 years; and
    (3) Make the record of seals available for MMS inspection.


Sec. 250.186  Measuring gas lost or used on a lease.

    What are the requirements for measuring gas lost or used on a 
lease?
    (a) Lessees must either measure or estimate the volume as required 
by the Regional Supervisor.
    (b) If the Regional Supervisor requires you to measure the volume, 
document the measurement equipment used and include the volume 
measured.
    (c) If the Regional Supervisor requires you to estimate the volume, 
document the estimating method and the data used and include the volume 
estimated.
    (d) Lessees must keep the volume estimates and documentation at the 
field location for 2 years.
    (e) If the Regional Supervisor requests, lessees must provide 
copies of the records.

[FR Doc. 97-4534 Filed 2-25-97; 8:45 am]
BILLING CODE 4310-MR-M