Oil and Gas Management
Interior's Oil and Gas Production Verification Efforts Do Not Provide Reasonable Assurance of Accurate Measurement of Production Volumes
Gao ID: GAO-10-313 March 15, 2010
Oil and natural gas produced from federal leases generated over $6.5 billion in royalties in 2009. To verify that royalties are paid on the correct volumes of oil and gas, the Department of the Interior (Interior) verifies the quantity and quality of oil and gas, both onshore, through the Bureau of Land Management, and offshore, through the Offshore Energy and Minerals Management Service. This report assesses (1) the extent to which Interior's production verification regulations and policies provide reasonable assurance that oil and gas are accurately measured; (2) the extent to which Interior's offshore and onshore production accountability inspection programs consistently set and meet program goals and address key factors affecting measurement accuracy; and (3) Interior's management of its production verification programs. To address these questions, GAO analyzed Interior data on oil and gas inspections and human capital, as well as interviewed officials from Interior, states, oil and gas companies, and other countries.
Interior's measurement regulations and policies do not provide reasonableassurance that oil and gas are accurately measured. Interior's varied approaches for developing and revising its measurement regulations are both ineffective and inefficient--Interior's onshore measurement regulations have not been updated in 20 years and do not address current measurement technologies. Onshore and offshore staff have infrequently coordinated on measurement issues, although each addresses similar issues. Additionally, Interior's decentralized process for granting waivers from current regulations and approval of alternative measurement technologies allows officials to make key decisions affecting measurement with little oversight, increasing the risk of approvals of inaccurate measurement technologies. Further, Interior has failed to determine the extent of its jurisdictional authority over key elements of oil and gas infrastructure, including gas plants and pipelines, limiting its ability to inspect these elements to assess the accuracy of their measurement. Finally, Interior's onshore and offshore policies for tracking and approving where and how oil and gas are measured are inconsistent, with Interior tracking offshore measurement points offshore, but not for onshore, creating challenges for onshore inspection staff to verify measurement accuracy. Interior's offshore and onshore production accountability inspection programs are not consistently setting or meeting program goals for inspecting oil and gas leases and do not sufficiently address key factors affecting measurement accuracy. Interior's offshore and onshore inspection program goals differ in key areas, with only the offshore program establishing goals for witnessing meter calibrations, a key control for accurate measurement. Additionally, while the onshore inspection program includes an activity to independently verify gas volume calculations, the offshore program does not. Moreover, Interior has not consistently met its inspection goals; offshore inspectors met program goals once between fiscal years 2004 and 2008, and onshore inspectors met program goals about one-third of the time over the past 12 years. Finally, neither program sufficiently addresses key areas affecting measurement accuracy, including how gas samples are collected. Limited oversight, gaps in staff skills, and incomplete tools hinder Interior's ability to manage its production verification programs. In particular, we identified several instances where production measurement staff work with limited oversight. For example, onshore engineers generally make decisions autonomously in the absence of central guidance and oversight. Further, despite years of critical reviews by GAO and others, Interior recently lowered its own estimation of the risks of the oil and gas program from medium to low, exempting it from more rigorous internal oversight. In addition, some key production verification staff lack critical skills, in part, because Interior has not provided training. For example, Interior has provided training only once in the past 10 years for its onshore engineers, despite significant changes in technology used by industry. Interior's efforts to provide its inspection staff with tools to obtain real-time gas production data directly from producers and the ability to electronically document production inspection results in the field have shown few results.
Recommendations
Our recommendations from this work are listed below with a Contact for more information. Status will change from "In process" to "Open," "Closed - implemented," or "Closed - not implemented" based on our follow up work.
Director:
Franklin W. Rusco
Team:
Government Accountability Office: Natural Resources and Environment
Phone:
(202) 512-4597
GAO-10-313, Oil and Gas Management: Interior's Oil and Gas Production Verification Efforts Do Not Provide Reasonable Assurance of Accurate Measurement of Production Volumes
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Measurement of Production Volumes' which was released on April 14,
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Report to Congressional Requesters:
United States Government Accountability Office:
GAO:
March 2010:
Oil And Gas Management:
Interior's Oil and Gas Production Verification Efforts Do Not Provide
Reasonable Assurance of Accurate Measurement of Production Volumes:
GAO-10-313:
GAO Highlights:
Highlights of GAO-10-313, a report to congressional requesters.
Why GAO Did This Study:
Oil and natural gas produced from federal leases generated over $6.5
billion in royalties in 2009. To verify that royalties are paid on the
correct volumes of oil and gas, the Department of the Interior
(Interior) verifies the quantity and quality of oil and gas, both
onshore, through the Bureau of Land Management, and offshore, through
the Offshore Energy and Minerals Management Service. This report
assesses (1) the extent to which Interior's production verification
regulations and policies provide reasonable assurance that oil and gas
are accurately measured; (2) the extent to which Interior‘s offshore
and onshore production accountability inspection programs consistently
set and meet program goals and address key factors affecting
measurement accuracy; and (3) Interior‘s management of its production
verification programs. To address these questions, GAO analyzed
Interior data on oil and gas inspections and human capital, as well as
interviewed officials from Interior, states, oil and gas companies,
and other countries.
What GAO Found:
Interior‘s measurement regulations and policies do not provide
reasonable assurance that oil and gas are accurately measured. Interior‘
s varied approaches for developing and revising its measurement
regulations are both ineffective and inefficient”Interior‘s onshore
measurement regulations have not been updated in 20 years and do not
address current measurement technologies. Onshore and offshore staff
have infrequently coordinated on measurement issues, although each
addresses similar issues. Additionally, Interior‘s decentralized
process for granting waivers from current regulations and approval of
alternative measurement technologies allows officials to make key
decisions affecting measurement with little oversight, increasing the
risk of approvals of inaccurate measurement technologies. Further,
Interior has failed to determine the extent of its jurisdictional
authority over key elements of oil and gas infrastructure, including
gas plants and pipelines, limiting its ability to inspect these
elements to assess the accuracy of their measurement. Finally, Interior‘
s onshore and offshore policies for tracking and approving where and
how oil and gas are measured are inconsistent, with Interior tracking
offshore measurement points offshore, but not for onshore, creating
challenges for onshore inspection staff to verify measurement accuracy.
Interior‘s offshore and onshore production accountability inspection
programs are not consistently setting or meeting program goals for
inspecting oil and gas leases and do not sufficiently address key
factors affecting measurement accuracy. Interior‘s offshore and
onshore inspection program goals differ in key areas, with only the
offshore program establishing goals for witnessing meter calibrations,
a key control for accurate measurement. Additionally, while the
onshore inspection program includes an activity to independently
verify gas volume calculations, the offshore program does not.
Moreover, Interior has not consistently met its inspection goals;
offshore inspectors met program goals once between fiscal years 2004
and 2008, and onshore inspectors met program goals about one-third of
the time over the past 12 years. Finally, neither program sufficiently
addresses key areas affecting measurement accuracy, including how gas
samples are collected.
Limited oversight, gaps in staff skills, and incomplete tools hinder
Interior‘s ability to manage its production verification programs. In
particular, we identified several instances where production
measurement staff work with limited oversight. For example, onshore
engineers generally make decisions autonomously in the absence of
central guidance and oversight. Further, despite years of critical
reviews by GAO and others, Interior recently lowered its own
estimation of the risks of the oil and gas program from medium to low,
exempting it from more rigorous internal oversight. In addition, some
key production verification staff lack critical skills, in part,
because Interior has not provided training. For example, Interior has
provided training only once in the past 10 years for its onshore
engineers, despite significant changes in technology used by industry.
Interior‘s efforts to provide its inspection staff with tools to
obtain real-time gas production data directly from producers and the
ability to electronically document production inspection results in
the field have shown few results.
What GAO Recommends:
GAO is recommending Interior improve the consistency and timely
updating of measurement regulations and policies, clarify
jurisdictional authority over gas plants and pipelines, and provide
appropriate and timely training for key measurement staff. In
commenting on a draft of this report, Interior generally agreed with
our findings and recommendations.
View [hyperlink, http://www.gao.gov/products/GAO-10-313] or key
components. For more information, contact Frank Rusco at (202) 512-
3841 or ruscof@gao.gov.
[End of section]
Contents:
Letter:
Background:
Interior's Measurement Regulations and Policies Do Not Provide
Reasonable Assurance that Oil and Gas Are Accurately Measured:
Interior's Differing Offshore and Onshore Production Accountability
Inspection Programs Do Not Consistently Meet Their Goals or
Sufficiently Address Key Factors Affecting Measurement Accuracy:
Limited Oversight, Gaps in Staffs' Critical Measurement Skills, and
Incomplete Tools Hinder Interior's Ability to Manage its Production
Verification Programs:
Conclusions:
Recommendations for Executive Action:
Agency Comments and Our Evaluation:
Appendix I: Scope and Methodology:
Appendix II: Comments from the Department of the Interior:
Appendix III: Four Examples of the Bureau of Land Management's (BLM)
Inconsistent Meter Approvals:
Appendix IV: Analysis of the Department of the Interior's (Interior)
Hiring, Training, and Retaining of Critical Measurement Staff:
Appendix V: Production Verification Tools and Practices Used by
Selected States, Companies, and Other Countries:
Appendix VI: Production Verification and Accountability Practices of
Selected States as Reported by State Officials:
Appendix VII: GAO Contacts and Staff Acknowledgments:
Related GAO Products:
Tables:
Table 1: Summary of Interior's Production Accountability Inspection
Program Goals and Components:
Table 2: OEMM Site Security Inspections for Oil and Gas Measurement,
Fiscal Year 2008:
Table 3: OEMM Liquid Oil and Gas Meter Calibrations Witnessed, Fiscal
Year 2008:
Table 4: Progress Toward Resolving Liquid and Gas Volume Discrepancies
and Obtaining Missing Production Allocation Reports, as of November
2009:
Table 5: Summary of BLM Production Inspections, Fiscal Years 1998-2009:
Table 6: Percentage Change in BLM Meter Calibration Activities
Completed, Fiscal Years 2004-2008:
Table 7: Percentage Change in BLM Tank Gauging Calibration Activities
Completed, Fiscal Years 2004-2008:
Table 8: BLM Production Inspection Activity Data, Fiscal Years 2004-
2008:
Table 9: Summary of Hiring, Training, and Retention Issues Identified
for Interior Production Verification Staff:
Table 10: Total Turnover Rates for Petroleum Engineers, Fiscal Years
2004-2008:
Table 11: Overview of Course Petroleum Engineer Technician Attendees
by Fiscal Years 2003-2008:
Table 12: Overview of Course Petroleum Engineer Technician Attendees
by Fiscal Years 2003-2008:
Table 13: Total Turnover Rates for Petroleum Engineer Technicians,
Fiscal Years 2004-2008:
Table 14: Total Turnover Rates for Production Accountability
Technicians, Fiscal Years 2004-2008:
Table 15: Total Turnover Rates for OEMM Petroleum Engineers who
Approve Measurement, Fiscal Years 2004-2008:
Table 16: Total Turnover Rates for OEMM Inspectors, Fiscal Years 2004-
2008:
Table 17: Number of Liquid Verification System (LVS) and Gas
Verification System (GVS) analysts, Fiscal Years 2004-2009:
Table 18: Establishment of Uncertainty Standards in Selected Entities'
Measurement Guidance:
Table 19: Entities Where Percentage Uncertainty Standards Are
Incorporated Into Measurement Guidance:
Table 20: Summary of Production Verification Practices in 10 States as
Reported by State Officials:
Figures:
Figure 1: BLM Field Offices and OEMM Regional and District Offices
Responsible for Managing Onshore and Offshore Federal Oil and Gas
Production:
Figure 2: Oil Tanks in Carlsbad, New Mexico:
Figure 3: BLM Petroleum Engineer Technician Preparing to Gauge an Oil
Tank:
Figure 4: A Lease Automatic Custody Transfer Unit:
Figure 5: An Orifice Meter with an Electronic Flow Computer:
Figure 6: OEMM Inspectors Witnessing a Calibration of an Orifice Meter
Associated With a Chart Recorder at a Land-Based Meter Location:
Figure 7: Oil Storage Tanks that Had Not Been Inspected for Several
Years:
Figure 8: BLM Petroleum Engineer Technician Inspecting an Orifice
Plate:
Figure 9: GAO Representation of BLM's Production Verification
Inspection and Enforcement Organizational Structure:
Figure 10: GAO Representation of OEMM's Production Verification and
Inspection Organizational Structure:
Figure 11: Volume Balancing Diagram Illustrating Gas Volumes Entering
and Leaving a System:
Abbreviations:
AFMSS: Automated Fluid Minerals Support System:
API: American Petroleum Institute:
BLM: Bureau of Land Management:
BTU: British Thermal Units:
DWRRA: Deep Water Royalty Relief Act:
EPAP: Enhanced Production Audit Program:
ERCB: Energy Resources Conservation Board:
FMFIA: Federal Managers' Financial Integrity Act:
FOGRMA: Federal Oil and Gas Royalty Management Act:
FPPS: Federal Personnel and Payroll System:
IT: Information Technology:
LACT: Lease Automatic Custody Transfer unit:
mcf: one thousand cubic feet:
MMS: Minerals Management Service:
NPR-A: National Petroleum Reserve-Alaska:
OMB: Office of Management and Budget:
OEMM: Offshore Energy and Minerals Management:
PCC: Production Coordination Committee:
RDAWP: Remote Data Acquisition for Well Production:
SCADA: Supervisory Control and Data Acquisition:
TIMS: Technical Information Management System:
[End of section]
United States Government Accountability Office:
Washington, DC 20548:
March 15, 2010:
Congressional Requesters:
Oil and natural gas produced from federal lands and waters are
critical to our nation's energy supply and reduce our reliance on
foreign sources of energy. Specifically, in fiscal year 2008, federal
lands and waters managed by the Department of the Interior (Interior)
contributed about 26 and 24 percent, respectively, to the total of oil
and gas produced in the United States. In fiscal year 2009, the
Department of the Interior's Minerals Management Service (MMS)
collected over $6.5 billion in royalties from companies that developed
and produced federal oil and natural gas. These royalties represent
one of the federal government's largest nontax sources of revenue.
Companies that develop and produce oil and gas from federal lands and
waters do so under leases obtained from and administered by agencies
of Interior--the Bureau of Land Management (BLM) for onshore leases,
and MMS's Offshore Energy and Minerals Management (OEMM) for offshore
leases. The oil and gas produced from these leases must be properly
measured and reported to MMS on a monthly basis. These volumes are
then used by MMS to verify that companies are accurately paying
royalties. Measuring oil and gas can be challenging at times, with
overall measurement accuracy affected by numerous factors, including
the type of meter used, the specific qualities of the gas or oil being
measured, the rate of production, and whether oil and gas of differing
qualities are mixed together from multiple wells prior to measurement.
Accordingly, both BLM and OEMM have independently established programs
intended to provide reasonable assurance that the royalty-bearing
volumes of oil and gas are being measured accurately. These programs
both have an on-the-ground inspection component that consists of
activities such as examining the pipelines delivering the oil and gas
from the well to the meter for possible diversion of oil and gas;
inspecting meter installations to ensure they meet agency standards;
and witnessing the calibration of meters, as well as an in-office
component consisting of comparisons of the monthly volumes included on
the MMS-required production reports with source measurement documents
obtained from the company. Given that proper measurement of oil and
gas is critical to accurate royalty collections, Interior's
measurement verification practices have been the subject of
considerable scrutiny through the years, both by GAO (see the Related
GAO Products section at the end of this report) and the Royalty Policy
Committee, a group convened in 1995 by the Secretary of the Interior
and charged with advising Interior on managing federal leases and
revenues. In September 2008, we reported that neither BLM nor OEMM was
meeting its statutory or internal goals for inspecting federal leases
that produce oil and gas and that Interior lacks assurance that the
royalty-bearing volumes are being accurately measured.[Footnote 1]
Furthermore, the Subcommittee on Royalty Management submitted a report
to the Royalty Policy Committee in December 2007 that included more
than 100 recommendations to strengthen Interior's royalty collections,
including many directed at improving oil and gas measurement and
reporting.[Footnote 2]
This report responds to your request that we examine Interior's
oversight of oil and gas measurement on federal leases. Accordingly,
our audit objectives were to assess (1) the extent to which Interior's
production verification regulations and policies provide reasonable
assurance that oil and gas are accurately measured; (2) the extent to
which Interior's offshore and onshore production accountability
inspection programs consistently set and meet program goals and
address key factors affecting measurement accuracy; and (3) Interior's
management of its production verification programs.
To conduct this work, we reviewed relevant laws, regulations, and
Interior, BLM, and OEMM guidance. We interviewed officials in BLM
headquarters, as well as officials from seven BLM field offices (and
their associated state offices), selected using a nonprobability
sample that provided a range of oil and gas operations and state
jurisdictions. Specifically, we visited and interviewed officials in
three BLM state offices (Colorado, New Mexico, and Wyoming) and seven
BLM field offices (Glenwood Springs[Footnote 3] and White River in
Colorado; Vernal in Utah; Buffalo and Pinedale in Wyoming; and
Carlsbad[Footnote 4] and Farmington in New Mexico) and interviewed by
telephone officials in two additional state offices (Montana and
Utah). Additionally, we interviewed officials in four OEMM district
offices (and their associated regional offices) that provided a range
of geographic and regional jurisdictions. Specifically, we visited and
interviewed officials in one OEMM regional office (Gulf of Mexico) and
one OEMM district office (Lafayette, Louisiana) and interviewed
officials in one additional OEMM regional office (Pacific) and four
additional OEMM district offices (Lake Charles, Lake Jackson, New
Orleans, and California) by telephone.
To assess the extent to which Interior's production verification
regulations and policies provide reasonable assurance that oil and gas
are accurately measured, we analyzed BLM's and OEMM's measurement
regulations and policies and conducted semistructured interviews with
engineers from seven BLM field offices, and inspection staff from nine
BLM field offices and four OEMM district offices. To assess the extent
to which Interior's onshore and offshore production accountability
inspection programs consistently set and meet program goals and
address key factors affecting measurement accuracy, we reviewed BLM's
and OEMM's production inspection policies, interviewed representatives
from oil and gas companies and flow measurement research labs about
key areas of measurement uncertainty, and analyzed BLM and OEMM
inspection data. To assess Interior's management of its production
verification programs, we reviewed BLM's and OEMM's internal plans for
conducting program oversight; reviewed a nonrandom and
nongeneralizable sample of hard copy BLM and OEMM inspection files;
analyzed BLM inspection activity data for fiscal years 2004 through
2008; analyzed human capital data for fiscal years 2004 through 2008
to calculate turnover rates; assessed BLM's and OEMM's training
programs for key production verification positions; and interviewed
BLM and OEMM officials responsible for developing two key IT tools
intended for production inspection staff and analyzed associated
project documentation. Appendix I presents a more detailed description
of our scope and methodology.
We conducted this performance audit between October 2008 and March
2010 in accordance with generally accepted government auditing
standards. Those standards require that we plan and perform the audit
to obtain sufficient, appropriate evidence to provide a reasonable
basis for our findings and conclusions based on our audit objectives.
We believe that the evidence obtained provides a reasonable basis for
our findings and conclusions based on our audit objectives.
Background:
Created by Congress in 1849, Interior oversees the nation's publicly
owned natural resources, including parks, wildlife habitat, and crude
oil and natural gas resources on millions of acres onshore and
offshore in the waters of the outer continental shelf. With regard to
oil and gas in particular, Interior leases federal land, issues
permits for oil and gas drilling, establishes guidelines for measuring
oil and gas, and conducts production inspections.
Leasing:
Onshore, the Mineral Leasing Act of 1920 gave Interior the
responsibility for oil and gas leasing on both federal lands and
private lands where the federal government has retained mineral
rights.[Footnote 5] Interior's BLM is responsible for managing
approximately 700 million onshore acres, including the acreage leased
for oil and gas development, through its 12 state offices; 38 district
offices; and 127 field offices, 32 of which have oil and gas
activities within their jurisdiction and are located mostly in the
western United States. BLM is also responsible for managing the
approximately 23 million acres of land in the National Petroleum
Reserve-Alaska (NPR-A) in the North Slope of Alaska. The Naval
Petroleum Reserve Production Act of 1976,[Footnote 6] as amended,
governs federal oil and gas leasing in the NPR-A. Offshore, the Outer
Continental Shelf Lands Act,[Footnote 7] as amended, and the Deep
Water Royalty Relief Act (DWRRA),[Footnote 8] as amended, gave
Interior the responsibility for leasing and managing approximately
1.76 billion offshore acres through its three OEMM regional and seven
district offices. These four statutes give Interior responsibility for
collecting royalties associated with both onshore and offshore oil and
gas production and serve as the basis for the current leasing
framework for oil and gas leasing (see figure 1).
Figure 1: BLM Field Offices and OEMM Regional and District Offices
Responsible for Managing Onshore and Offshore Federal Oil and Gas
Production:
[Refer to PDF for image: U.S. map]
The map depicts the location of the following:
BLM field offices:
Anchorage, Alaska;
Bakersfield, California;
Canon City, Colorado;
Casper, Wyoming;
Dickinson, North Dakota;
Grand Junction, Colorado;
Great Falls, Montana;
Jackson, Mississippi;
Kemmerer, Wyoming;
Lander, Wyoming;
Little Snake, Colorado;
Miles City, Montana;
Milwaukee, Wisconsin;
Newcastle, Wyoming;
Price/Moab, Utah;
Rawlins, Wyoming;
Reno, Nevada;
Rock Springs, Wyoming;
Salt Lake City, Utah;
San Juan Public Lands Center, Colorado;
Tulsa, Oklahoma;
Worland/Cody, Wyoming.
BLM field offices we reviewed:
Buffalo, Wyoming;
Carlsbad/Hobbs, New Mexico;
Farmington, New Mexico;
Glenwood Springs, Colorado;
Pinedale, Wyoming;
Roswell, New Mexico;
Vernal, Utah;
White River, Colorado.
OEMM district offices:
Houma, Louisiana;
Lafayette, Louisiana;
OEMM district offices we reviewed:
Lake Charles, Louisiana;
Lake Jackson, Texas;
Los Angeles, California;
New Orleans, Louisiana.
OEMM regional offices:
Alaska Regional Office.
OEMM regional offices we reviewed:
Gulf of Mexico Regional Office;
Pacific Regional Office.
Sources: BLM and Map Resources (map).
[End of figure]
Permitting:
To drill on federal lands and waters, companies must first obtain a
federal lease. Both MMS and BLM have auctions through which companies
may secure the rights to federal leases that allow them to--upon
meeting certain conditions--drill for oil and gas. Once it obtains a
lease, a company may conduct further exploration and subsequently
determine whether it would like to drill a well. Onshore, before a
company may drill on leased lands, it must submit an Application for
Permit to Drill to the appropriate BLM field office. BLM officials
evaluate the company's proposal for drilling to ensure that it
conforms with the relevant BLM land use plan for the area and
applicable laws and regulations, including those focused on protecting
the environment. In evaluating an Application for Permit to Drill, a
BLM petroleum engineer reviews technical aspects of the proposed well
design and drilling practices. In most cases, a BLM petroleum engineer
will not need to specifically approve any oil or gas measurement
equipment if a company plans to use metering technologies addressed by
BLM's measurement regulations. However, if requested to do so by a
company, BLM will also consider whether to approve a variance from
current regulations governing the use of alternative metering
technologies. After BLM approves a drilling permit, the company--or
operator--may drill the well and commence production. Within 60 days
of drilling, the operator must file a site facility diagram that
accurately reflects the relative positions of the production
equipment, piping, and metering systems.
A similar process is followed for obtaining a permit to drill a well
offshore. In this case, the operator submits an application for a
drilling permit to the appropriate OEMM district office, where the
district engineer first reviews it for completeness. After reviewing
the technical elements of the application and verifying that they
conform with all applicable regulations, the district engineer
approves the permit. Only after a permit is approved can drilling
begin. Once drilling is completed--and if the operator discovers that
oil and gas can be economically produced from the well--the operator
submits an application to the appropriate OEMM regional office to
begin production that describes, among other things, how oil and gas
will be measured. If the application is approved, the regional office
assigns a facility measurement point, which is an identifier for each
location where oil and gas will be measured.
Royalty Payments to the Federal Government:
Interior is also responsible for ensuring that the federal government
receives payment from the private companies that extract oil and gas
from federal land. When an operator begins producing oil or gas under
a federal lease, the royalty interest owners--or payors--pay royalties
on the oil or gas produced monthly according to the following equation:
Royalty payment = (sales volume x sales price - deductions) x the
royalty rate:
Royalty rates for leases issued in 2007 were 12.5 percent for onshore,
16.67 percent for offshore, and 12.5 percent or 16.67 percent for NPR-
A. Importantly, MMS gas valuation regulations allow royalties to be
paid on the sales value of gas after it has been processed at a gas
plant. For processed gas, the volume measured at either BLM's or
OEMM's official measurement point will not coincide with the final
sales volume for royalty determination, as natural gas liquids may be
removed prior to the gas plant. Furthermore, as the gas passes through
the gas plant, various constituents are separated out of the gas
streams and the end products--including gas types such as propane,
ethane, and butane--are sold to various markets. Royalties are due on
the sales value of each of these separate gas constituents. A
productive lease remains in effect and the lessee can continue to
produce oil and gas until the lease is no longer capable of producing
in paying quantities, regardless of the length of the primary term.
Within Interior, MMS is also responsible for revenue collection.
[Footnote 9] MMS does this by, among other things, obtaining reports
from payors on the amounts of oil and gas produced, the prices
received for production, any deductions claimed, and the royalty rate
applicable to the production.
Oil and Gas Measurement:
Interior has established specific regulations and other mechanisms for
how oil and gas may be measured. The degree of certainty that both the
quantity and quality of oil and gas are being measured accurately can
be affected by multiple factors. Because 100 percent measurement
accuracy is not possible, measurement specialists commonly refer to
uncertainty ranges--or ranges of expected values. Both regulators and
industry acknowledge this uncertainty and, to varying extents,
incorporate uncertainty ranges into their measurement requirements.
What both regulators and industry attempt to avoid, however, is bias--
or systematic error. Bias refers to when the volumes are consistently
over-or under-measured. Therefore, the goal for measuring oil and gas
is to minimize uncertainty and to eliminate bias. How--and the extent
to which--this is achieved varies between oil and gas, but key
controls include using the appropriate meter and other processing
equipment for the situation; witnessing meter calibrations; witnessing
sales; and verifying that volume calculations were completed
accurately. Additional controls include following measurement
standards intended to reduce uncertainty that have been generally
agreed upon by industry and regulators and published by the American
Petroleum Institute (API). Since the passage of the National
Technology Transfer and Advancement Act in 1996, federal agencies have
been required to adopt private-sector standards, such as API's,
wherever practical, in lieu of creating their own proprietary,
nonconsensus standards.[Footnote 10]
Oil. According to an Interior official, most oil produced from federal
lands and waters is measured through one of two very different
methods. First, oil can be measured by periodically physically
estimating the volume of accumulated oil--a process called tank
gauging--which is used when oil is pumped directly from the well into
a large cylindrical tank(s), typically located adjacent to the well.
This is common onshore in locations where wells are not located
adjacent to oil pipelines. The tank is used to store the oil until a
tanker truck pumps the oil out and delivers it to a pipeline or other
facility. These tanks can be 20 or more feet tall and hold hundreds of
barrels or more of oil (see figure 2).
Figure 2: Oil Tanks in Carlsbad, New Mexico:
[Refer to PDF for image: photograph]
Source: GAO.
[End of figure]
Tank gauging is a manually intensive measurement process whereby the
gauge, a device similar to a tape measure, is used to determine the
depth of oil in the tank both before and after the oil has been pumped
from the tank to the truck. Then, using a conversion table specific to
that tank, the gauger--or person gauging the tank--converts the
difference in the before and after depths into an overall volume. At
the same time, the gauger obtains representative samples of the oil in
the tank and tests them to determine the extent to which impurities,
such as water and sediment, are present.[Footnote 11] This entire
process may be performed by the drivers of the tanker trucks, who
drive routes through oil fields, picking up oil at many tanks along
the way and delivering it to a central location where it is shipped,
via pipeline, to refineries or other locations (see figure 3). This
entire process is called a tank sale, and a receipt recording the
amount of oil removed is prepared and later provided to the operator.
Because tank gauging is a manual process, the accuracy of the
measurement depends on the extent to which the gauger adheres to
requirements established by Interior, which reference API standards.
There are several procedures that must be strictly followed to ensure
measurement accuracy during a tank sale. For example:
* If the gauger does not follow standards endorsed by API, which
include procedures for minimizing uncertainty and eliminating bias,
errors in measurement can occur. For example, incorrectly measuring
the depth of the oil in the tank due to the presence of unevenly
distributed sediment on the tank bottom; a tank deformation, such as a
dent; or using the wrong table to convert the tank depth to a volume
would result in inaccurate measurement.
* If the impurities present in the oil are not measured according to
API standards, the volume of oil will be inaccurately measured.
* Since oil tanks are often in remote locations and not supervised,
there is risk that oil can be stolen. Because of this risk, Interior
has policies for securing tank valves.
Figure 3: BLM Petroleum Engineer Technician Preparing to Gauge an Oil
Tank:
[Refer to PDF for image: photograph]
Source: GAO.
[End of figure]
The second primary method for measuring oil involves the use of lease
automatic custody transfer (LACT) units. These are automated systems
for measuring, sampling, recording, and transferring oil from wells to
a pipeline or a barge, and are common on the higher production rate
platforms in the Gulf of Mexico. Historically, these units have been
equipped with positive displacement meters--which operate similarly to
a gasoline pump--though other types of meters may be used as well (see
figure 4). With this method, a critical factor for minimizing
uncertainty is to ensure the meter is accurate. To ensure meters
remain accurate through many years of use after manufacture, they must
be calibrated--or proved--regularly. Meters are proved by comparing
their measurement with the measurement of another device, such as a
prover. The prover is itself tested for accuracy and must be clearly
traceable to national measurement standards maintained by the U.S.
National Institute of Standards and Technology. If the prover has
fallen out of calibration, or the individual calibrating the meter is
unfamiliar with the process, the measurement may be biased. API has
standards specifying how often meters and provers must be tested.
Figure 4: A Lease Automatic Custody Transfer Unit:
[Refer to PDF for image: photograph]
Source: GAO.
[End of figure]
Gas. Because gas produced at a well may flow at various pressures,
thereby resulting in larger or smaller compressed volumes of
marketable components, gas is generally measured using meter devices
that are different from those used for measuring oil. Gas produced
from federal lands and waters is typically measured using one of a
variety of differential pressure devices, such as an orifice meter.
Orifice meters have been in use for almost 100 years and are the most
common device used to measure federal natural gas production. These
meters force gas to flow through a circular piece of metal with a hole
in it, called an orifice plate, to create a pressure difference
(higher in front of the plate and lower behind it). Differential
pressure and temperature data are measured by sensors allowing the
volume of gas to be calculated based on equations developed by the
American Gas Association. Historically, these data were physically
recorded on a paper chart located near the meter and had to be
interpreted manually. Since the early 1990s, industry has begun to use
electronic flow computers to calculate the gas volumes, which are in
widespread use today. Electronic flow computers are attached to the
meter to track key parameters for calculating volumes and a variety of
other information, such as when the meter was last calibrated and what
size orifice plate is in the meter (see figure 5).
Figure 5: An Orifice Meter with an Electronic Flow Computer:
[Refer to PDF for image: 2 photographs]
The following are labeled on the photographs:
Electronic flow computer;
Orifice plate fitting;
Orifice plate;
Meter tube.
Source: GAO.
[End of figure]
A number of factors affect the accuracy of gas measurement.
* Orifice and meter tube condition. Both the orifice plate and the
meter tubes located upstream of the meter must be free of nicks or
pits; not have a significant accumulation of debris, such as wax or
other contaminants that commonly occur in gas production; and be
installed correctly. Research shows that imperfections on the surface
of the orifice plate, dirty meter tubes, or installing the plate
backward can result in under measurement.
* Orifice size. The orifice plate must be appropriately sized for the
volume of flowing gas. If too large a plate is used, the differential
pressure will be lower, resulting in higher levels of uncertainty.
* Measurement of all gas. Gas production sites are often complex, with
many pipes above and below ground. It is important that no pipes that
can carry gas are allowed to bypass the meter so that all gas leaving
the well is measured.
* Presence of water or liquid hydrocarbons in the gas stream. Most
measurement standards require the gas being measured to be free of
liquids--meaning that any water or liquid hydrocarbons mixed with the
gas when it was produced have been removed. This is typically
accomplished using separators and dehydrators located at the well
site. According to an Interior official, gas measurement will be
biased upward when liquids are present in the gas stream.
* Meter installation. The meter must be installed in a location where
the gas is flowing freely and uniformly. For this to be the case,
typically the meter must be placed a specified distance from bends in
the pipes and other obstructions. In some cases, the flow of gas can
be conditioned using devices to eliminate flow that could negatively
affect measurement. API and other industry organizations have
developed guidance specific to various meter types, for orifice meter
size and placement, and the use of devices to condition the flow.
Industry is also developing and using newer and, in some cases, more
complex gas metering technologies, including Wafer V-Cone, turbine,
ultrasonic, Coriolis, and multiphase meters; however, these meters are
less widely used for measuring federal gas than orifice meters.
[Footnote 12] API has established some standards for the use of some
of these meters. Each of these meters is also associated with various
factors that can potentially result in inaccurate measurement.
In addition to volume, determining the quality of the gas is also
necessary. Gas typically has many different components--methane,
ethane, and butane, among others--that may be separated during
processing at a gas plant and subsequently sold. The composition of
the gas gives it its overall heating value, which is reported in
British thermal units (BTU).[Footnote 13] The higher the BTU content,
the higher the market value; thus, the sale price of the gas. The gas
may be sampled through one of several different methods, including
taking spot samples which involves taking a one-time gas sample from a
point adjacent to the meter, or proportional-to-flow samples, which
involves collecting a sample of gas over a specified period of time.
[Footnote 14] Most gas samples have associated water content that can
be precisely determined through the gas analysis, resulting in the
actual BTU. However, if the analysis does not specifically assess the
water content, then one can report the BTU value on a dry basis if it
is assumed that no water is present, or on a wet basis, if it is
assumed the gas is saturated.
Commingling Oil and Gas. Interior has the authority to approve
measurement agreements that allow oil or gas produced from a federal
lease to be combined with oil or gas from another federal, state, or
private lease; these agreements allow the combined volumes and varying
qualities of oil or gas to be measured at some specified point
downstream, rather than at each individual well head. Each upstream
lease is then allocated a specific portion of the combined volume
according to the commingling agreement. Operators may request approval
for commingling for several reasons, including the need to reduce
costs of installing and maintaining meters in marginally producing
fields and to simplify their measurement operations. Additionally, BLM
may encourage this practice to reduce the need for additional
equipment at each well head, which reduces the environmental impacts
on the land surrounding the well. However, the accuracy of the
measurement of oil or gas produced may be affected by commingling.
Production Inspections:
To ensure compliance with all stipulations in the lease and conditions
of approval in the drilling permit, as well as applicable laws and
regulations, both BLM and OEMM have inspection and enforcement
programs that are designed to verify that the operator complies with
all measurement requirements at a well site. The authority for
inspecting wells for this purpose is derived from the Federal Oil and
Gas Royalty Management Act of 1982 (FOGRMA), as amended.[Footnote 15]
This act requires the Secretary of the Interior to develop guidelines
that specify the coverage and frequency of inspections.[Footnote 16]
Interior has delegated responsibilities for implementing FOGRMA; BLM
has responsibility for onshore wells, and OEMM has responsibility for
offshore wells. Each agency has developed regulations, policies, and
procedures to conduct inspections. Together, BLM and OEMM are
currently responsible for ongoing oversight of oil and gas operations
on more than 29,000 producing leases. Among other things, BLM and OEMM
staff inspect leases to verify that oil and gas production is
accounted for, as required by FOGRMA and agency regulations and
policies. Finally, in many instances both onshore and offshore, the
operators do not own or maintain the custody transfer meter--the meter
where gas and oil are transferred from one party to another--which
measures the oil and gas produced. Rather, that meter is owned and
maintained by a pipeline company that is paid by the operator to
transport the oil or gas to some point downstream.
Onshore. Production inspections are BLM's primary mechanism for
ensuring that operators are complying with various measurement
regulations and policies. BLM staff conduct production inspections to
provide reasonable assurance that oil and gas produced from federal
leases are being measured and handled appropriately. BLM's petroleum
engineer technicians are responsible for conducting production
inspections, in addition to other types of inspections, including
drilling, well plugging, and abandonment inspections. Petroleum
engineer technicians conduct and track production inspections by
inspecting cases--a case is either a lease or a unit agreement
[Footnote 17] which can have between 1 to over 1,000 wells--to verify
that oil and gas are being measured in accordance with regulations and
policies. Production inspections typically consist of four key
activities: (1) reviewing 6 months of production records to look for
any anomalies, (2) assessing the physical conditions of the production
area by looking for refuse or any leaking equipment, (3) verifying
that the company-submitted site security diagram--which should include
all the piping and equipment at the site--reflects what is actually at
the site, and (4) examining a sample of both oil and gas measurement
operations. For example, this examination may involve witnessing a gas
meter calibration, independently recalculating the gas production
volumes using key values recorded by the electronic flow computer, or
gauging an oil tank. BLM production accountability technicians also
complete in-office detailed reviews of meter statements, calibration
records, and oil and gas production volumes reported to MMS.
Offshore. OEMM's efforts to verify measurement consist primarily of
physical inspections of oil and gas production platforms, and an
automated comparison of operator-reported production data with volume
data generated by pipeline companies. OEMM's inspectors are
responsible for a variety of inspections, including safety and
environmental, as well as those focusing on oil and gas production.
OEMM's production inspections include verifying that piping connected
to the meter is sealed to prevent theft and ensuring there are no
bypasses around meters that could allow oil or gas to flow unmeasured.
Additionally, OEMM inspectors witness oil and gas meter calibrations.
OEMM also automatically compares operator-reported oil and gas
production volumes with pipeline oil run tickets and gas volume
statements through its Liquid Verification System and Gas Verification
System. These programs require that operators submit gas volume
statements and oil run tickets produced at OEMM's official metering
points, called facility measurement points, that are used for royalty
determination purposes. The volumes recorded on these statements,
along with other technical information, are electronically and
manually entered by OEMM staff. OEMM's database then compares these
volumes with the monthly operator-reported production volumes, and
forwards discrepancies to MMS. MMS staff then follow up with the oil
or gas companies and work to reconcile the volume differences.
[Footnote 18]
Interior's Measurement Regulations and Policies Do Not Provide
Reasonable Assurance that Oil and Gas Are Accurately Measured:
Interior's measurement regulations and policies do not provide
reasonable assurance that oil and gas are accurately measured because
(1) its varied approaches for developing and revising its offshore and
onshore regulations are ineffective and inefficient, (2) it has a
decentralized process for approving new measurement technologies not
addressed by current regulations, (3) it has not determined the extent
of its authority over key elements of oil and gas production
infrastructure, and (4) its policies for tracking where and how oil
and gas are measured are not consistent and effective.
Interior's Varied Approaches for Developing and Revising Its Offshore
and Onshore Measurement Regulations Are Both Ineffective and
Inefficient:
Interior's approaches for developing and revising its offshore and
onshore oil and gas measurement regulations differ, at times hindering
Interior's ability to accurately measure oil and gas production. Since
these regulations were first promulgated, they have been ineffectively
revised and, in some cases, do not reflect current measurement
technologies or industry standards. Finally, little coordination has
occurred between OEMM and BLM, resulting not only in inefficient and
duplicative efforts in reviewing and assessing new measurement
technologies and practices, but a missed opportunity to take advantage
of measurement expertise across agencies.
Interior's Offshore and Onshore Measurement Regulations Differ,
Permitting Inconsistent Measurement of Oil and Gas:
Interior's regulations for measuring oil and gas vary depending on
whether the production is from an offshore or onshore federal lease,
resulting in inconsistent oil and gas measurement practices and, in
some instances, reducing Interior's assurances of accurate
measurement. More specifically, in 1982, the Secretary of the Interior
transferred authority for offshore and onshore oil and gas measurement
to MMS and BLM, respectively. Accordingly, each agency developed its
own set of measurement regulations which have varying requirements for
how oil and gas should be measured. Some variations between Interior's
offshore and onshore measurement regulations may be appropriate
because of the differences between offshore and onshore oil and gas
production volumes and operating environments. For example, OEMM
regulations require that offshore meters be calibrated more frequently
than BLM regulations require for its onshore meters. Given the
relatively higher volumes of oil and gas typically flowing through
offshore meters, more frequent calibrations help ensure that even
small meter errors are corrected before large volumes are measured
incorrectly, according to measurement specialists. Other variations
between offshore and onshore measurement regulations are more
problematic. For example, orifice plates that are free of nicks, pits,
and grooves are critical for accurate gas measurement both onshore and
offshore. BLM has regulations requiring operators to inspect the
orifice plates every six months to ensure they are free of these
defects.[Footnote 19] In contrast, OEMM regulations reference API
guidelines that highlight the importance of orifice plate inspections,
but do not prescribe frequencies for operators to conduct these
inspections.[Footnote 20] This omission increases the risk of
inaccurate offshore gas measurement because OEMM does not have
sufficient assurance that the orifice plate is free of nicks and other
imperfections. Similarly, Interior approves the use of electronic flow
computers both onshore and offshore for calculating gas volumes.
However, while OEMM has a regulation specifying the conditions under
which electronic flow computers may be used; BLM relies on individual
states' policies. While these state policies are generally the same,
they were issued separately over 5 years, resulting in inconsistent
application of requirements and standards when approving these devices
during this period. This lack of a consistent departmentwide
regulation on the use of electronic flow computers increases the risk
that gas may not be measured accurately.
Interior Lacks an Integrated Approach for Ensuring Both its Offshore
and Onshore Measurement Regulations Are Consistently Revised to
Reflect Current Measurement Technologies:
Interior lacks an integrated approach for ensuring that both its
offshore and onshore measurement regulations are consistently updated
to reflect current industry measurement technologies and practices,
which would increase Interior's assurance that oil and gas are
measured accurately. While OEMM has an established approach for
annually reviewing its measurement regulations and has kept them
reasonably updated, BLM does not have such an approach, and as a
result, its measurement regulations have not been revised since 1989.
OEMM routinely updates its offshore oil and gas measurement
regulations, most recently in 2009 when it established post-hurricane
meter verification and calibration requirements. As a result of OEMM's
annual reviews of its regulations, they generally reflect both current
technologies and the oil and gas industry's voluntary consensus
measurement standards. OEMM employs two methods to help maintain its
regulations. First, it has an office of approximately nine full-time
regulatory specialists and engineers who, among other things, annually
review oil and gas industry standards, including API's measurement
standards, upon which OEMM's measurement regulations are largely
based. As part of this review, staff assess whether any revisions to
industry standards referenced in current regulations represent a
technological or process change significant enough to require an
update to OEMM's regulations. OEMM's regulatory officials also
coordinate with OEMM's regional production and development staff--
staff responsible for approving how offshore oil and gas will be
measured--to consider the likely impact of the revised industry
standard. If both parties agree that updating the regulations is
necessary, regulatory staff prepare a memorandum outlining the
proposed change for MMS management to review. If MMS management
approves the proposed regulatory change, the proposal continues
through Interior's rule making process, which may or may not require
public comment. Second, OEMM has also established a streamlined
process to incorporate industry standards into its regulations when
certain criteria are met--as set forth in the Administrative Procedure
Act.[Footnote 21] In 1996, MMS issued a regulation that allows OEMM to
incorporate industry standards by reference without public comment
when MMS determines that the revisions to an industry standards
document will either improve safety or represent standards for newer
technology used by industry, and will not impose undue costs on the
affected parties.[Footnote 22] For example, MMS first adopted API's
1993 standards for the use of electronic flow computers in 1998; when
MMS updated its regulations to meet API's 2005 reaffirmed standards in
2007, it did so without soliciting public comment. According to OEMM
officials, when notice and comment are not required, the rule making
process is 6 to 12 months faster than when they are required. Overall,
in part because of these two methods, OEMM's measurement regulations
have been updated 10 times since 1988, 9 of which occurred after the
1996 change to include regulatory standards by reference.
In contrast, BLM has neither a dedicated staff to review changes to
standards referenced by its regulations nor a regulation allowing it
to update its regulations by reference when certain criteria are met.
In part, because it lacks such an effective approach, BLM last revised
its oil and gas measurement regulations in 1989. As a result, BLM's
regulations do not reflect current industry adopted measurement
technologies and standards designed to improve oil and gas
measurement. According to a senior BLM official, BLM generally relies
on a single method for determining whether its measurement regulations
need to be updated. While BLM does not have any specific personnel
formally tasked with monitoring changes in either measurement
technologies or industry measurement standards, BLM field office staff
and BLM management may use an informal process to reach consensus that
various sections of BLM's oil and gas regulations need updating. This
process has resulted in two attempts since 1989 to update BLM's
regulations, neither of which ended in revised measurement
regulations. The first attempt began in the early 1990s, when BLM
published proposed gas measurement regulations in the Federal Register
in 1994 for public comment. These regulations would have addressed,
among other things, electronic flow computers. Because these
regulations were not finalized, BLM did not formally address
electronic flow computers in some jurisdictions until 10 years later
and, only then, through BLM policy changes on a state-by-state basis.
BLM's second attempt occurred in the late 1990s, when it proposed
revisions to all of its oil and gas regulations and planned to publish
them in the Code of Federal Regulations; however, after BLM drafted
200 pages of regulations and published them in the Federal Register in
1998, they were never finalized.
BLM is now attempting for the third time to update its measurement
regulations. In December 2007, Interior's Subcommittee on Royalty
Management raised concerns about BLM's measurement regulations and
recommended that BLM re-evaluate them.[Footnote 23] Specifically, the
subcommittee recommended that BLM establish a working group to
evaluate its oil and gas measurement and site security regulations to
ensure that they include adequate guidance for BLM to provide
reasonable assurance that sufficient royalties are paid on oil and
gas. For example, the subcommittee suggested that when BLM reviews its
gas measurement regulations, it evaluate the use of electronic flow
computers and gas sampling and analysis, among other areas. Although
the subcommittee set a June 2008 deadline for BLM to complete this
work, in April 2009, Interior's Inspector General issued a report that
evaluated BLM's progress and found that BLM had not yet established a
work group to evaluate its regulations.[Footnote 24] However, instead
of empanelling a committee to work exclusively on this large task, BLM
has asked staff to volunteer to do this work along with their other
responsibilities, with the consent of their supervisors. An official
told us that obtaining approval from local supervisors for staff to
participate in these working groups was a challenge and may have
contributed to the delay. In August 2009, a senior BLM official told
us that even if the regulatory process was fast-tracked, the revised
measurement regulations would be issued at the end of 2011, at the
earliest. According to this official, the work groups had been
established and would begin drafting proposed regulations soon.
Interior's Offshore and Onshore Staff Have Infrequently Coordinated on
Measurement Regulations Resulting in Inefficient, Duplicative Efforts:
Historically, according to both OEMM and BLM officials, there has been
limited communication between the agencies regarding measurement
regulations and other measurement issues. As a result, Interior does
not have a coordinated approach for addressing measurement issues that
draws on measurement expertise from both OEMM and BLM. Interior has,
at various times, had staff from both OEMM and BLM independently
reviewing and assessing the same industry standards that are
referenced in both OEMM's and BLM's regulations, the results of which
are not shared with one another, raising the likelihood that they may
reach different conclusions. Furthermore, when industry develops new
metering and measurement technologies and subsequently writes
standards to address their use, staff from both agencies independently
assess the new technology's effectiveness. For example, both OEMM and
BLM have approved V-Cone meters for measuring royalty-bearing gas.
However, the agencies did not coordinate to assess the technology or
accuracy of the meter. Rather, staff from both OEMM and BLM each
devoted time and resources to examining the meter. While BLM obtained
the company-funded research evaluating the conditions under which the
V-Cone meters could accurately measure gas, BLM did not share these
findings with OEMM. As a result, there is a risk that the conditions
for which meters are approved for onshore measurement and for offshore
measurement may be different and that these different conditions may
have varying effects on the accuracy of the oil or gas measurement.
Interior is currently addressing some of these coordination issues
through its Production Coordination Committee and its subteams which
specifically address oil and gas measurement issues, which were
established in response to a recommendation made by the Royalty Policy
Subcommittee on Royalty Management. The Production Coordination
Committee, established in 2008 and composed of BLM, OEMM, and MMS
staff, is responsible for both implementing 22 of the over 100
recommendations that require intradepartmental coordination included
in the subcommittee's December 2007 report, as well as facilitating
ongoing internal coordination, communication, and information sharing
between BLM, OEMM, and MMS. According to an MMS official, one outcome
of this effort to facilitate coordination was a November 2009 joint
BLM and MMS workshop that provided an opportunity for staff to share
applicable best practices and discuss common oil and gas production
concerns, including production verification, commingling and
allocation, gas sampling, and auditing requirements. While other BLM
and OEMM officials told us that the agencies are now communicating
with one another more frequently, both BLM and OEMM continue to
independently update and revise their measurement regulations.
Interior's Decentralized Process for Approving New Measurement
Technologies Not Addressed by Current Regulations Increases the Risk
of Inaccurate Oil and Gas Measurement:
Interior lacks a centralized review process for approving technologies
not addressed by current regulations, increasing the risk of
inaccurate oil and gas measurement. When a company wants to use a
technology that is not addressed by regulations, it requests specific
approval to do so, referred to as a variance, from Interior.[Footnote
25] Interior has delegated this decision making authority to both OEMM
and BLM, which has resulted in the agencies developing approaches that
are inconsistent with one another for assessing these requests. These
inconsistent approaches may increase the risk of inaccurate
measurement.
OEMM's process for granting approvals is centralized and the resulting
decisions are generally consistent. OEMM chose to retain decision
making about variances at the regional level, where OEMM possesses
specialized production measurement expertise, as opposed to delegating
this responsibility to its district offices, which do not have such
expertise. Because decisions to approve variances are centrally made
and reviewed by engineers solely responsible for measurement issues,
these variances are generally consistent. Most OEMM variance requests
are reviewed in OEMM's Gulf of Mexico Production and Development
office, which oversees production of most federal offshore oil and gas
activity. For example, OEMM recently approved a request from one
company to use ultrasonic meters to measure royalty-bearing gas. In
making this decision, OEMM staff evaluated both the performance data
on the proposed meter's accuracy as well as the economic aspects of
using the meter, which in this instance, suggested that measurement
costs could be lowered by reducing the need for additional pipelines
and space on a platform. Because OEMM's internal control environment
is structured so that these decisions are centrally made by staff
whose primary responsibility is measurement, there is less risk of a
meter being approved that results in inaccurate measurement.
In contrast, BLM's approval process for variances from its measurement
regulations are not centralized and approvals are not reviewed by
specialized measurement staff; in some instances inconsistent
decisions have been made, raising the risk that oil and gas
measurements were inaccurate. For example, in some cases, where
current measurement regulations do not apply and the BLM national or
state offices have not provided formal guidance, the field office's
authorized officer--who may or may not have a petroleum engineering
degree or expertise in measurement issues--decides whether to approve
a variance from current measurement regulations without further review
or notifying BLM at the national level.
We found that in BLM's approvals of four measurement technologies:
electronic flow computers, Wafer V-Cone meters, truck-mounted Coriolis
meters,[Footnote 26] and flow conditioners,[Footnote 27] were either
not consistently made, not centrally reviewed, or both. For example,
BLM documents indicate that authorized officers at different field
offices initially approved Wafer V-Cone meters--a type of differential
pressure meter that was marketed as having the ability to accurately
measure gas mixed with water--but that the operating conditions for
which they were approved were inconsistent. After these initial
approvals, BLM, at the national level, participated in a work group
that assessed research paid for by the meter manufacturer to determine
under what conditions the meters could accurately measure gas. The
results of the research, which was completed in 2005, confirmed that
BLM had previously approved the use of Wafer V-Cone meters for
conditions outside of the meters' ability to accurately measure the
gas. BLM issued a nationwide Instruction Memorandum in November 2006
specifying the conditions under which BLM's authorized officers could
approve Wafer V-Cone meters, as well as requiring that all previously
approved Wafer V-Cone meters be brought into compliance.[Footnote 28]
In response, one of the field offices we visited sent a letter to all
companies in its jurisdiction in January 2009--over 2 years after BLM
issued its Instruction Memorandum--requesting that all companies
submit a plan to BLM outlining how they would bring any noncompliant
Wafer V-Cone meters into compliance by May 2009. As a result,
according to a BLM official, some royalty-bearing gas was inaccurately
measured over a period of several years and resulted in costs to
companies that were required to retrofit measurement installations
that had been approved by BLM. Additionally, because BLM management
does not centrally review approvals made by authorized officers at the
field offices, they are unaware of what approvals are made at the
field office level. For example, in November 2008, the BLM national
office issued a nationwide Instruction Memorandum requesting
information on the number of field offices that had approved truck-
mounted Coriolis meters for oil measurement.[Footnote 29] This
incident suggests that BLM management was both unaware of how
frequently this technology was being used and what measurement
performance data were used by field office authorized officers in
granting any variances (see appendix III for further details).
Furthermore, we found that within BLM field offices, the authority of
the authorized officer is inconsistently delegated to one of several
different BLM positions, which have different professional
backgrounds. For example, in four of the seven field offices we
visited, the petroleum engineers have approval authority, in two field
offices the associate field office manager has approval authority, and
in one field office a petroleum engineer technician has approval
authority. In addition, according to BLM staff who make decisions on
whether to approve variances, they typically request supporting
technical information from the operator; conduct Internet searches for
related material to review; and, in some cases, consult with
authorized officers in other field offices, though there is no
requirement to do so prior to making a decision on an application for
a variance.
Recently, BLM established a Gas Measurement team, as recommended by
the Subcommittee on Royalty Management in December 2007, to assess new
gas measurement technologies and consider other measurement issues;
however, the team consists of staff who have volunteered for the task,
subject to approval from their supervisors. Furthermore, the team
members must split their time between their primary job
responsibilities and their new role in assessing the technologies and
considering measurement issues--potentially limiting the amount of
time that they can devote to the gas measurement tasks. According to
one member of the Gas Measurement team, this has created some
challenges, as there are a large number of measurement issues that BLM
needs to address, yet they have limited staff available to devote to
the task. Finally, the team currently serves in an advisory role by
assisting the authorized officers who have authority at the field
office level. At the time of our site visits to seven BLM field
offices, from March through May 2009, some staff stated that they
would coordinate with the newly established Gas Measurement team,
while others did not tell us whether they would coordinate with the
team.
Interior Has Not Determined the Extent of Its Authority over Key
Elements of Oil and Gas Production Infrastructure Necessary for
Ensuring Accurate Measurement:
Interior has not determined the extent of its authority over two key
elements of oil and gas production infrastructure that are necessary
for ensuring accurate measurement: (1) meters in (or after) gas plants
which, in some cases, may include the meter where oil and gas are
measured for royalties; and (2) meters owned by pipeline companies,
which frequently own, operate, and maintain the meter used at the
official measurement point on federal leases, as well as the
production data the meter generates.
Interior's Failure to Determine the Extent of Its Authority over
Certain Gas Plant Sales Meters Has Resulted in Limited Oversight of
Measurement at Certain Gas Plants, Reducing Assurances that Royalty-
Bearing Volumes Are Being Correctly Measured:
Interior has exercised limited oversight over certain gas plants
because it has failed to determine the extent of its authority for
overseeing gas plants that process gas produced both onshore and
offshore and what regulatory standards apply to the meters used in gas
plants to measure royalty-bearing federal production. Gas plant meters
are critical in determining accurate royalty payments as, often,
operators measure the unprocessed gas at the well head and transfer
the gas to a gas plant. Gas plants further refine unprocessed natural
gas into various constituents upon which royalty payments are due.
Beside methane, which is the most common constituent, these
constituents include butane, propane, ethane, and other products that
can be used in a variety of ways, including residential heating,
transportation, and plastic manufacturing. Because many of these other
sales products may have higher market values than natural gas used in
homes, royalties paid on these components can be responsible for a
significant share of royalties provided by a lease. As such, any
inaccurate measurement at gas plants could significantly impact
royalties that are due to the federal government. Accordingly,
ensuring that sales products are accurately measured is essential for
determining the correct royalty amount. Until recently, Interior had
not physically inspected gas plant meters used to measure royalty-
bearing gas production--except in the Pacific region, where OEMM
approved official measurement royalty points in the gas plant.
According to officials and documents obtained from Interior, for over
20 years, there has been a history of uncertainty as to which agency
had both the legal authority and regulatory responsibility to inspect
gas plant meters. For onshore gas plants, BLM and MMS have attempted
to bring resolution to this uncertainty but, so far, they have been
unsuccessful. For example:
* BLM and MMS established a Gas Plant task force in the mid-1980s to
examine agency roles and responsibilities and industry requirements
related to the gas stream, from the well head to the gas plant tail
gate--meters measuring processed natural gas products. The central
question the task force addressed was, "What are the roles of BLM and
MMS in ensuring that the United States fully receives royalties due
from the sale of all products produced from the gas stream?" The task
force concluded that BLM would ensure that oil and gas were measured
correctly before they leave the federal lease and that MMS would
conduct a reasonableness check, through a formula, that gas plant
products were correctly allocated back to the correct federal lease.
The task force further concluded that MMS could make special requests
to BLM to examine meters at a gas plant, if necessary; but that, in
general, BLM's role regarding gas plants was very limited. One key
finding of the task force was the existence of a "a void in regulatory
connection between BLM's 'measurement point' and MMS's 'sales point,'"
though no specific actions were taken to address this. Finally, the
task force concluded that, in general, while the government should
generally be assured that the gas plant products are being accurately
measured, verifying this is not among BLM's highest priorities.
* BLM and MMS revisited this issue in 1996 when they established an
Oil and Gas Royalty Measurement Point/Gas Accountability work group to
address, in part, potential oversight gaps between BLM's point of
measurement and MMS's sales point at a gas plant. The work group
raised the issue that the BLM point of measurement and the MMS sales
point were two different points; with BLM's point of measurement
typically located upstream of MMS's sales point. A document from one
of the work group's meetings stated that "independent verification of
actual volumes measured at the sales point (e.g., a meter in a gas
plant), against what has been reported as sold, is not being conducted
by either agency [BLM or MMS]." The memo further concluded that,
"Additionally, all measurement for sales purposes which occurs after
the BLM approved point of measurement does not require approval or
need to meet any standards for accuracy," meaning that meters used to
measure products upon which royalties are due are not required to meet
any regulatory standards for accuracy.
As of September 2009, according to a BLM official, meters used in gas
plants to measure onshore royalty-bearing federal production did not
have to meet federal standards, and BLM did not independently verify
volumes measured at gas plants. According to a senior BLM official,
the reason BLM does not inspect meters in gas plants is that, until
recently, BLM assumed that this was MMS's responsibility. When we
discussed gas plants with BLM staff at field offices, some petroleum
engineer technicians did express some concern about the accuracy of
royalty payments based on how products were both handled and measured
downstream of BLM's point of measurement. However, most BLM staff were
not concerned because they considered anything past their point of
measurement beyond their jurisdiction.
Similarly, OEMM has not determined the extent of its authority over
gas plants processing gas produced offshore, which has resulted in
OEMM's exercising minimal oversight over measurement issues in Gulf of
Mexico gas plants. While OEMM did issue a regulation in 1998 allowing
OEMM inspectors to inspect meters in gas plants, according to Interior
officials, this provision has historically been used in cases where
the lease operator owned the gas plant--which, because of industry
consolidation and pipeline infrastructure, is common only in the
Pacific region.[Footnote 30] However, officials told us that, more
commonly in the Gulf of Mexico, gas plants are not owned by the
operator and OEMM has not determined its authority in these cases.
Accordingly, OEMM does not have regulations specifically addressing
the types of meters used in gas plants or standards for how often
these meters are calibrated; and, until recently, has not conducted
any inspections of gas plants, thereby increasing the uncertainty
about whether royalty-bearing gas is being properly measured.
In December 2008, because of concerns raised by the Associate Director
of OEMM about the lack of oversight at gas plants, OEMM initiated a
comprehensive review of all gas plants in the Gulf of Mexico region
processing royalty-bearing offshore federal gas. OEMM's efforts
identified 37 gas plants, of which 27 were then processing federal
gas; the remaining 10 gas plants were not operating because of the low
volumes of gas being produced from the Gulf of Mexico. OEMM's
inspections, which began in June 2009, included obtaining or creating
a site-security diagram for the gas plant, identifying all meters
associated with the plant, reviewing meter calibration reports, and
identifying potential bypasses around royalty determination meters.
OEMM plans to use some of these data to create a gas plant database
that could be used for future audits. These gas plant inspections
identified several potential areas of concern. First, OEMM identified
one instance of possible misreporting of gas production. Each month,
operators are required to submit to MMS their monthly production
reports which, among other things, indicate which gas plant the
operator's gas is being transferred to for processing. In this
instance, an OEMM official found that the total monthly volume
attributed to a particular gas plant for processing was significantly
greater than the plant's total gas processing capacity for a month.
Second, OEMM identified several instances in which meters had not been
calibrated in accordance with OEMM's measurement regulations. Finally,
OEMM identified piping configurations in gas plants that would
potentially allow royalty-bearing gas streams to bypass the royalty
sales point without being measured.
Interior's Office of the Solicitor is now reviewing what legal
authority BLM and OEMM have for inspecting gas plants, and whether or
not regulations need to be written or revised. According to Interior's
attorneys, they began the review of OEMM authority in May 2009, and
BLM requested a review of its authority in September 2009.
Interior Has Not Determined the Extent of Its Authority over Meters
and Pipelines, Limiting Production Verification Efforts:
Interior has not determined the extent of its authority to obtain
production data from meters designated as the official point of
measurement or its authority over the meters themselves, when they are
owned by pipeline companies; thus, limiting Interior's ability to
access key production data and equipment necessary for verifying
production.[Footnote 31] While Interior has some statutory authority
over pipelines and other shippers, such as tanker trucks that
transport oil and gas produced from federal leases, neither BLM nor
OEMM has issued regulations to enable Interior to implement this
authority.[Footnote 32] This creates two challenges for both BLM's and
OEMM's production verification. First, because Interior currently does
not obtain production and meter information directly from the pipeline
companies, it relies on operators to provide the information.
According to some Interior staff, obtaining the documents necessary
for audits from the operators instead of the pipeline company is both
inefficient and time-consuming. Several BLM staff at both the state
and field office level with whom we spoke said that they have
encountered situations where the operator did not have the required
production records necessary for BLM to verify production--such as oil
tank gauging records, meter calibration records, and gas analysis
reports. In these instances, BLM worked through the operator to obtain
the documents from the pipeline company. In one instance, a BLM
official told us that during a meeting to discuss how BLM would obtain
the necessary production documentation with both the operator and the
pipeline company, a pipeline company official initially refused to
provide BLM the documents, explaining that BLM did not have
jurisdiction over pipelines. In these instances, BLM enters into a
protracted interaction with the involved parties, which often results
in BLM's requesting oil and gas production companies--either
operators, lessees, or both--to obtain these records from the pipeline
companies, which lengthens the time it takes for BLM inspection staff
to verify production.
Second, Interior's uncertainty about its authority over the physical
meter itself when it is owned by the pipeline company complicates
Interior's efforts to schedule appointments to witness meter
calibrations or other inspections--a critical control for ensuring
accurate measurement. For example, some offshore inspectors told us
that they had, in several instances, not been able to witness meter
calibrations as planned because the pipeline company staff changed
their schedule for calibrating a specific meter without notice. As a
result, OEMM inspectors are less able to meet their goals for
witnessing meter calibrations. Additionally, the unnecessary cost OEMM
incurs for flying an inspector out to a platform to witness a meter
calibration is significant--up to $5,000. According to OEMM officials,
they currently have no direct recourse with the pipeline company when
they cancel the calibration without providing notice.
Interior's Policies for Tracking Where and How Oil and Gas Are
Measured are Not Consistent or Effective, Reducing Assurance that Oil
and Gas Are Being Measured and Reported Accurately:
Interior, which has delegated responsibility for oil and gas
production verification to OEMM and BLM, tracks measurement points
offshore but not onshore, thereby reducing Interior's assurance that
oil and gas are being accurately measured and reported. [Footnote 33]
Additionally, while Interior has developed specific policies and
instituted controls for reviewing and approving offshore commingling
requests,[Footnote 34] it has not done the same for onshore
commingling requests, creating situations where, according to staff,
verifying production is difficult.
Interior Does Not Consistently Track All Measurement Points, Resulting
in Uncertainty about the Location of Meters Measuring Oil and Gas
Produced from Federal Lands:
Interior tracks offshore measurement points to assist in verifying oil
and gas production, but not onshore measurement points, which creates
uncertainty about the location of the official point of measurement
and complicates production verification work. Offshore, OEMM tracks
the number and location of its official points of measurement by
assigning a facility measurement point number to each point of
measurement. Each facility measurement point number, in turn, is
associated with one or more meters that are numerically identified
with meter ID numbers. In addition, MMS requires that operators report
their monthly production volumes by their facility measurement point.
OEMM subsequently matches these volumes with volumes generated by the
pipeline companies and recorded on oil run tickets or gas volume
statements. In this way, OEMM is able to identify the measurement
point for all volumes of offshore oil and gas produced and to verify
reported production compared with meter production records.
Onshore, BLM does not track either the number or location of its
official measurement points for each lease--routinely called the point
of measurement and described as the last meter before the oil or gas
leaves the lease. This lack of tracking complicates BLM's production
verification efforts. Moreover, MMS does not require onshore operators
to report meter identification information, such as an ID number, on
the monthly production reports, as it does for offshore operators.
This makes it difficult to associate the oil or gas production
reported on the monthly production report with any particular meter on
the lease. Current measurement regulations require that all onshore
oil and gas be measured on the lease or within the boundaries of the
associated unit, unless BLM allows an operator to measure the
production off-lease--at a location other than the lease where it was
produced. However, BLM has no regulatory or policy requirement for the
operator to clearly identify the point of measurement or provide BLM
with specific identifying information. The absence of a clear
identifier for the point of measurement has created challenges for BLM
in verifying production and operators in reporting production. BLM
petroleum engineer technicians and production accountability
technicians verify production, in part, through ensuring the point of
measurement meter is functioning properly and comparing operator-
reported volumes on the monthly production report to production
information recorded by the meter. Without clear identification of the
point of measurement in the field and a meter ID number on the monthly
production report, BLM staff may not be able to correctly identify the
point of measurement. BLM staff with whom we spoke from nine field
offices expressed a range of views on the difficulty they have with
identifying the point of measurement while conducting production
inspections. Generally, BLM petroleum engineer technicians said that
when the point of measurement is at the well head, it is easy to
identify; however, when off-lease measurement has been approved,
locating the point of measurement can be challenging. Petroleum
engineer technicians in most of the nine field offices stated that
having clear documentation of the point of measurement would assist
them in completing their inspections.
Additionally, some BLM staff stated that operators may be unaware of
the location of the official BLM point of measurement, resulting in
misreporting production. Specifically, field offices have experienced
cases in which operators measured and reported gas from unapproved off-
lease central delivery points--central locations at which gas from
multiple leases or units is measured. These meters may be measuring
commingled federal, private, and state production, which the operators
allocate back to individual wells located upstream. According to BLM
staff, it is unclear whether operators are doing this intentionally or
unintentionally. To address some of this uncertainty, the Wyoming BLM
state office issued an Instruction Memorandum addressing this issue in
2003, after it determined that operators were using off-lease central
delivery point allocation systems, which led to significant
discrepancies between the operator-allocated volumes and the point of
measurement volumes.[Footnote 35] The memorandum further stated that
without a clear understanding of where BLM's point of measurement is,
it is impossible to correctly account for production volumes, among
other things. More recently, in March 2009, the Pinedale, Wyoming,
field office issued a letter to all the operators in its jurisdiction
stating that "due to the changing composition of production facilities
and point of measurement for many wells, the Pinedale field office
finds it necessary to require operators to provide additional
measurement information for purposes of verifying production and
measurement," which include posting at each lease site a list of all
wells that flow through each of the measurement devices located on the
lease.
Interior's Inconsistent Policies and Processes for Approving
Commingling Agreements Compound Its Difficulties in Ensuring that Oil
and Gas Are Accurately Measured:
Interior's offshore and onshore policies for approving specific
agreements for how oil and gas can be measured after being combined
with oil or gas from another lease--commingling agreements--are
inconsistent. OEMM has explicit policies and a centralized process for
approving specific agreements for how oil and gas can be commingled.
In contrast, BLM lacks a clear policy and uses a decentralized
process, which makes its staffs' efforts to verify production
difficult. As a general rule, because offshore commingling involves
only federal production, offshore commingling agreements may be less
complex than onshore commingling agreements, which may include
federal, state, and private production.
Offshore, OEMM reviews requests for commingling agreements at a single
office in each of its regional offices, rather than delegating this
responsibility to petroleum engineers in its district offices. In
addition, in the Gulf of Mexico, where the majority of commingling
agreements are reviewed, each request is reviewed by two different
supervisors to ensure consistency. Additionally, OEMM guidance
provides criteria for evaluating commingling and allocation agreements
in the Gulf of Mexico region. For example, to protect federal royalty
interests, OEMM guidance instructs petroleum engineers not to allow
production from leases with different royalty rates to be commingled
without a separate measurement that meets API standards because,
according to an agency official, production may be misallocated to a
lease with a different royalty rate, resulting in inaccurate royalty
payments. Moreover, OEMM requires operators with commingling
agreements that involve nonfederal production to not only report
production on their monthly production report, but to separately
report their allocated production on a monthly production allocation
schedule report. The purpose of this report is to provide additional
information about how allocated volumes are divided among different
leases in a commingling agreement. This report provides OEMM and MMS
with an additional control for verifying commingled production, since
the data are corroborated by the operators' monthly production report.
In contrast, BLM lacks sufficient policies and a consistent process
for determining whether to allow federal production to be commingled
with other federal, state, or private production prior to measurement.
This results in complicated commingling agreements that, according to
BLM staff, make verifying production difficult. BLM's policy for
reviewing and approving requests to commingle and allocate production
includes fewer criteria than OEMM's and creates significant challenges
for BLM's petroleum engineer technicians and production accountability
technicians in verifying production. Operators may submit a request to
commingle production to their local BLM field office, where a
petroleum engineer typically reviews the request and determines
whether to approve it. According to petroleum engineers in six of the
seven field offices we visited, however, there is a lack of sufficient
BLM national guidance on how to review the requests. As a result,
petroleum engineers we met with told us they rely, instead, on a
variety of other guidance, including guidance produced at the field or
state office level. For example, petroleum engineers from two field
offices--one in Utah and one in Wyoming--told us that they consider
criteria included in an Interior Geological Survey Conservation
Division Manual, issued in 1974. A petroleum engineer from Wyoming
provided us with Wyoming BLM general guidance dated May 2001 that was
applicable to Wyoming field offices. Finally, a petroleum engineer
from a field office in New Mexico told us he considers criteria from
both local BLM guidance issued in 1995 and the findings of a 1994
joint BLM and Industry Off-lease Sales, Usage, and Measurement
Subcommittee report. While there are similarities among these guidance
documents, it appears as though BLM staff are not routinely
referencing uniform national guidance and, therefore, are increasing
the risk that when presented with similar commingling requests, they
may make different decisions. Seemingly inconsistent decisions have
caused at least one operator to raise the issue to a BLM State
Director. In this instance, the operator's request to commingle
production at one field office had been denied; whereas, according to
the operator, the same types of commingling requests were routinely
approved at another field office within the same state. Additionally,
BLM currently has no guidance on what role either petroleum engineer
technicians or production accountability technicians--staff who verify
commingled production--have in reviewing and approving commingling
requests. While the majority of petroleum engineers we spoke with in
the seven field offices stated that when approving a commingling
agreement, they would consider the effect on the petroleum engineer
technicians' and production accountability technicians' capacity to
ensure that production is measured and reported accurately; petroleum
engineers from one field office said they would not.
Finally, petroleum engineer technicians and production accountability
technicians--staff responsible for ensuring that production of oil and
gas is accurately reported--told us that commingling and allocation
agreements create significant challenges for verifying production, and
the lack of guidance exacerbates the challenges. In all seven field
offices we reviewed, production accountability technicians--those most
responsible for conducting in-depth record reviews to ensure
production is accurately reported--stated that when production is
commingled prior to measurement, verifying production is significantly
more difficult. Furthermore, several production accountability
technicians acknowledged that, even after completing an in-depth
records review, they were not confident that all production was being
properly measured and accounted for, and that the complexities of
these agreements may make it nearly impossible, in some cases, to
ensure that production is accurately attributed to the appropriate
lease. This inability to confidently verify production greatly
increases the risk that misreported volumes and their associated
royalty payments will go undetected.
Interior's Differing Offshore and Onshore Production Accountability
Inspection Programs Do Not Consistently Meet Their Goals or
Sufficiently Address Key Factors Affecting Measurement Accuracy:
Interior's production accountability inspection programs for offshore
and onshore differ in key areas. Additionally, Interior is not
consistently completing either its offshore or onshore required
production inspections. Finally, Interior's offshore and onshore
production inspection programs do not sufficiently address key factors
affecting measurement accuracy, thereby increasing the risk that oil
and gas are not being accurately measured.
Although Interior's Offshore and Onshore Production Accountability
Inspection Programs Have Recently Been Revised, They Differ in Key
Areas:
Interior's offshore and onshore oil and gas production accountability
inspection programs have been revised multiple times in the past
several years, with each program inconsistently emphasizing different
key measurement inspection goals and activities intended to provide
reasonable assurance that oil and gas are measured accurately.
OEMM Recently Revised its Production Accountability Inspection
Program, Which Emphasizes Annual Goals for Witnessing Meter
Calibrations and Site Security Inspections:
OEMM's production accountability inspection program--which emphasizes
annual goals for its offshore inspectors to witness meter calibrations
and conduct site security inspections--has been revised twice in the
past 2 years. From 1994 until 2007, OEMM's inspection program required
annually witnessing the calibration of 5 percent of gas royalty
meters, the proving of 10 percent of oil royalty meters, and
conducting site security inspections on all offshore platforms and
measurement locations (see figure 6). In 2008, we found that OEMM had
not defined key terms for its inspection program and recommended that
the Secretary define "significant quantities of oil or gas" and
"history of noncompliance."[Footnote 36] In 2008, OEMM established an
interim annual goal of conducting site security inspections on the
highest producing 100 oil and gas platforms in the Gulf of Mexico,
while leaving its goals for witnessing meter calibrations unchanged.
[Footnote 37] Finally, in 2009, OEMM implemented our recommendation by
revising its inspection program to incorporate definitions for
"significant quantities of oil and gas" and "history of
noncompliance." OEMM's current annual inspection goals are to:
* witness the proving of 10 percent of oil meters and the calibration
of 5 percent of gas meters;
* annually inspect the site security of all high-producing oil and gas
facilities--defined as those facilities that produce more than 1,000
barrels of oil per day, or the equivalent heating value for
gas[Footnote 38] and all other locations on a 3-year cycle; and:
* continue to reinspect all platforms that have been placed on the
Monthly Operators Compliance list--a list OEMM district offices use to
track violations that inspectors find during their work--until the
violation has been corrected.
Figure 6: OEMM Inspectors Witnessing a Calibration of an Orifice Meter
Associated With a Chart Recorder at a Land-Based Meter Location:
[Refer to PDF for image: photograph]
Source: GAO.
[End of figure]
OEMM inspection staff can perform two measurement-related activities
while inspecting a measurement location: (1) witnessing meter
calibrations, and (2) completing a site security inspection. According
to Interior officials and oil and gas company measurement staff,
witnessing calibrations is recognized as a strong control for ensuring
accurate measurement. OEMM staff told us that their presence when
company staff are calibrating the meters is a key mechanism for
ensuring proper measurement of federal oil and gas production.
Conducting site security inspections verifies that offshore platforms
and other measurement facilities meet OEMM's regulations concerning
the handling of oil and gas production. Such inspections typically
include a visual examination of piping to verify that oil and gas do
not flow around--or bypass--measurement meters.
However, OEMM does not conduct certain activities that BLM uses to
verify gas production, such as independently verifying electronic flow
computer gas calculations. According to an OEMM official, for a short
period of time in 1988, OEMM independently verified gas meter volume
calculations while conducting inspections; however, this practice was
discontinued when measurement inspections were incorporated into
OEMM's overall inspection program at the district office level.
Further, unlike BLM, which has through state policies established a 3
percent overall uncertainty limit for gas measurement that
incorporates uncertainties introduced by the temperature reading, the
differential pressure reading, and the overall meter installation,
among other inputs; OEMM has not. To assess compliance with the 3
percent uncertainty, BLM worked with a private independent lab with
expertise in flow measurement to develop an "uncertainty calculator"
that allows BLM staff to input data and determine the overall
measurement uncertainty for any given gas measurement configuration.
When we asked an OEMM official about why OEMM had not established an
overall uncertainty level, the official told us OEMM had not
considered including the concept in its production verification
processes.
OEMM district offices track violations that inspectors find during
their work in a monthly operators' compliance list, maintained at the
district level. Once OEMM staff place a facility with a history of
violations on their tracking list, OEMM inspects the facility at least
once every four months until the district manager determines that the
operator has remedied the violation; at which point, the operator is
removed from the Monthly Operator Compliance list. Currently, these
violations are not formally tracked on an OEMM-wide basis, limiting
OEMM's oversight of operators that have violations.
Finally, in addition to OEMM's witnessing meter calibrations and site
security inspections, MMS has additional checks on the accuracy of
operator-reported production volumes called the Liquid Verification
System and the Gas Verification System. Each month, OEMM staff use
these systems to compare the operator-reported oil and gas volumes
with volumes of oil and gas measured by pipeline company meters, which
OEMM recalculates based on raw meter data. When volumes do not match,
MMS staff work to reconcile the volumes through meeting with operators
and requesting additional documentation.
BLM's Recently Revised Production Accountability Inspection Program
Includes Several Key Activities beyond Witnessing Meter Calibrations
and Inspecting Site Security, Although BLM Lacks Annual Goals for
Witnessing and Other Measurement Activities:
BLM's production inspection program--which was recently revised--
differs from OEMM's inspection program in several ways. Prior to
fiscal year 2009, BLM's production inspection program required staff
to annually inspect all cases--BLM's unit of inspection, which may be
one or several leases containing from 1 to over 200 wells--rated as
high priority for production, or those producing at least 12,000
barrels of oil or 120,000 thousand cubic feet (mcf) per month. In
addition, staff were required to inspect all high priority compliance
cases--cases where the operator had six or more FOGRMA-related
incidents of noncompliance, or two or more major incidents of
noncompliance, within a 24-month period. The production inspection
program further required inspections once every 3 years on all other
cases. For fiscal year 2009, BLM lowered the criteria for "high
production," thereby increasing the number of high priority production
inspections--or cases that require annual production inspections.
BLM's current production accountability inspection program requires
the following:
* annual inspections of high priority production cases--producing, on
average, 6,000 barrels of oil or 80,000 mcf of gas per month--and
inspections once every 3 years for all remaining cases, and:
* annual inspections of high priority compliance cases--cases where
the lease operator has had two major, or a total of six or more FOGRMA-
related incidents of noncompliance with BLM regulations in the
preceding 24 months.
BLM's production inspection program also includes a wider range of
activities than OEMM's inspection program; however, unlike OEMM, BLM
has not established annual goals for witnessing oil and gas meter
calibrations. Specifically, BLM inspectors complete one of two types
of production inspections. The first type requires inspectors to
complete four separate components for each producing case: (1) an
assessment of the case's site security, including whether any bypasses
around the meter are present; (2) a surface protection review, or
visual examination of the surrounding surface area for trash or other
items that should not be there; (3) a review of 6 months of operator-
reported production reports; and (4) an oil or gas measurement
activity. Several of the measurement activities are similar to OEMM's
activities, including witnessing oil and gas meter calibrations and
witnessing a tank gauging; however, BLM has no annual goals for
specific measurement activities. Alternatively, BLM staff may conduct
an in-depth records review, which are more detailed examinations of
oil and gas production documents.
BLM conducts several key measurement activities that OEMM does not,
including both in-depth record reviews and verifications of gas
volumes calculated by electronic flow computers. BLM's production
accountability technicians generally conduct the in-depth record
reviews by routinely asking operators to provide volume data generated
by the meters, which they compare with the monthly operator-reported
production volumes.[Footnote 39] During these record reviews,
production accountability technicians may also review additional
documentation on both meter calibrations and gas samples, both of
which are used to verify production. Additionally, petroleum engineer
technicians and production accountability technicians may elect to
verify the calculated gas volume on the electronic flow computer. This
verification typically requires staff to record such factors as
temperature, differential pressure, and sometimes, the integral value--
a key factor required to verify gas volumes--and to recalculate the
volume in accordance with the American Gas Association gas volume
equation. Recalculating gas volumes can provide assurance that the
electronic flow computer's software is accurately calculating the
volumes. As a result of this activity, BLM has found instances where
the electronic flow computer is incorrectly calculating volumes. As
one petroleum engineer technician explained, BLM staff identified at
least one particular model of an electronic flow computer that was
incorrectly calculating volumes, which caused the operator to hire a
consultant to further study the problem. In contrast, as previously
mentioned, OEMM does not check the calculations of the electronic flow
computers. Also, as mentioned previously, BLM developed an overall 3
percent uncertainty limit for gas measurement, as well as software to
calculate the uncertainty.
When petroleum engineer technicians identify violations of BLM's
regulations in the field, BLM policy is to issue an "incident of
noncompliance." These incidents of noncompliance, depending on the
severity of the violation, may either be minor or major. For example,
according to current BLM regulations, off-lease measurement of gas
without prior approval is generally considered a minor violation,
whereas not recording the temperature of oil to the nearest degree
during a sale is typically considered a major violation. BLM personnel
in each field office track these incidents of noncompliance data in
BLM's database. However, BLM does not use an overall assessment of
operators' compliance across field offices as criteria for high
priority compliance cases. Consequently, when a BLM field office
places a case in its high priority inspection category, it does not
consider an overall assessment of the operator's compliance on federal
cases outside of a particular field office's jurisdiction.
Accordingly, being placed on the high priority list by one field
office has no impact on how the same operator is viewed by another
field office. As a result, the same operator may have multiple major
incidents of noncompliance; by not tracking across field office
jurisdictions, BLM is also limited in its oversight of an operator's
noncompliance (see table 1).
Table 1: Summary of Interior's Production Accountability Inspection
Program Goals and Components:
Goals and components: Defined "high producing";
BLM: Yes;
OEMM: Yes.
Goals and components: Defined "history of noncompliance";
BLM: Yes;
OEMM: Yes.
Goals and components: Established annual goal for witnessing gas meter
calibrations;
BLM: No;
OEMM: Yes.
Goals and components: Established annual goal for witnessing oil meter
calibrations;
BLM: No;
OEMM: Yes.
Goals and components: Established annual goal for witnessing oil tank
gaugings;
BLM: No;
OEMM: Yes.
Goals and components: Review site security diagrams and inspect for
meter bypasses;
BLM: Yes;
OEMM: Yes.
Goals and components: Track incidents of noncompliance across
jurisdiction boundaries;
BLM: No;
OEMM: No.
Goals and components: Verify electronic flow computer volume
calculation;
BLM: Optional;
OEMM: No.
Goals and components: Use a gas volume uncertainty calculator;
BLM: Optional;
OEMM: No.
Goals and components: Perform volume reconciliation - comparisons
between operator-reported volume data and pipeline-generated volume
data;
BLM: Optional;
OEMM: Yes.
Goals and components: Receive meter calibration reports;
BLM: Optional;
OEMM: Yes.
Source: GAO analysis.
[End of table]
Interior Has Not Routinely Achieved Its Oil and Gas Production
Accountability Inspection Annual Goals, Which Reduces Its Assurance
that Oil and Gas Are Measured Accurately:
Neither OEMM nor BLM has consistently completed statutory or agency
required production inspections, a key control for verifying oil and
gas production. Offshore, OEMM met its oil and gas site security and
calibration witnessing inspection goals once between fiscal years 2004
and 2008 for the four district offices we reviewed. Onshore, BLM met
its minimum goal of inspecting all producing cases once every 3 years,
approximately one-third of the time over the past 12 years in the six
field offices with reliable data we reviewed.[Footnote 40]
OEMM Met its Annual Production Inspection Goals Once in 5 Fiscal Years:
Offshore, for the four district offices we reviewed, OEMM met its oil
and gas site security and calibration witnessing inspection goals only
once--2008--during fiscal years 2004 through 2008. In 2008, OEMM's
site security goal for the Gulf of Mexico, its major production area,
was to conduct inspections on the 100 highest-volume measurement
locations; its goal in the Pacific region was to inspect all meters.
See tables 2 and 3 for more detailed data for the four district
offices we reviewed.
From 2004 through 2007, OEMM's goals were to conduct site security
inspections on 100 percent of all measurement locations. During those
years, the agency performed about half of the site security
inspections required to meet the annual goals. OEMM staff told us
that, during these years, there was a shortage of inspectors and
inspections were delayed because of the ongoing cleanup related to
Hurricanes Katrina and Rita in 2005. We are unable to present data for
these years because, according to OEMM officials, district offices
often did not correctly record site security inspections on their
inspection forms. This problem was identified in 2007; since then,
OEMM has instituted a new policy to ensure that these inspections are
being recorded correctly.
Table 2: OEMM Site Security Inspections for Oil and Gas Measurement,
Fiscal Year 2008:
District office: Lake Charles;
Inspection activity: Meters requiring inspection;
Oil: Meters in the top 100 highest volume measurement locations: [A];
Oil: All other active meters: 124;
Gas: Meters in the top 100 highest volume measurement locations: 16;
Gas: All other active meters: 520.
District office: Lake Charles;
Inspection activity: Meters inspected;
Oil: Meters in the top 100 highest volume measurement locations: [A];
Oil: All other active meters: 118;
Gas: Meters in the top 100 highest volume measurement locations: 16;
Gas: All other active meters: 484.
District office: Lake Charles;
Inspection activity: Percentage inspected;
Oil: Meters in the top 100 highest volume measurement locations: [A];
Oil: All other active meters: 95;
Gas: Meters in the top 100 highest volume measurement locations: 100;
Gas: All other active meters: 93.
District office: Lake Jackson;
Inspection activity: Meters requiring inspection;
Oil: Meters in the top 100 highest volume measurement locations: 15;
Oil: All other active meters: 121;
Gas: Meters in the top 100 highest volume measurement locations: 25;
Gas: All other active meters: 410.
District office: Lake Jackson;
Inspection activity: Meters inspected;
Oil: Meters in the top 100 highest volume measurement locations: 15;
Oil: All other active meters: 116;
Gas: Meters in the top 100 highest volume measurement locations: 25;
Gas: All other active meters: 347.
District office: Lake Jackson;
Inspection activity: Percentage inspected;
Oil: Meters in the top 100 highest volume measurement locations: 100;
Oil: All other active meters:96;
Gas: Meters in the top 100 highest volume measurement locations: 100;
Gas: All other active meters: 85.
District office: New Orleans;
Inspection activity: Meters requiring inspection;
Oil: Meters in the top 100 highest volume measurement locations: 61;
Oil: All other active meters: 170;
Gas: Meters in the top 100 highest volume measurement locations: 48;
Gas: All other active meters: 342.
District office: New Orleans;
Inspection activity: Meters inspected;
Oil: Meters in the top 100 highest volume measurement locations: 61;
Oil: All other active meters: 164;
Gas: Meters in the top 100 highest volume measurement locations: 48;
Gas: All other active meters: 313.
District office: New Orleans;
Inspection activity: Percentage inspected;
Oil: Meters in the top 100 highest volume measurement locations: 100;
Oil: All other active meters: 96;
Gas: Meters in the top 100 highest volume measurement locations: 100;
Gas: All other active meters: 92.
District office: California[B];
Inspection activity: Meters requiring inspection;
Oil: Meters in the top 100 highest volume measurement locations: 19;
Oil: All other active meters: [B];
Gas: Meters in the top 100 highest volume measurement locations: 15;
Gas: All other active meters: [B].
District office: California[B];
Inspection activity: Meters inspected;
Oil: Meters in the top 100 highest volume measurement locations: 19;
Oil: All other active meters: [B];
Gas: Meters in the top 100 highest volume measurement locations: 15;
Gas: All other active meters: [B].
District office: California[B];
Inspection activity: Percentage inspected;
Oil: Meters in the top 100 highest volume measurement locations: 100;
Oil: All other active meters: [B];
Gas: Meters in the top 100 highest volume measurement locations: 100;
Gas: All other active meters: Total: [B].
District office: Total;
Inspection activity: Meters requiring inspection;
Oil: Meters in the top 100 highest volume measurement locations: 95;
Oil: All other active meters: 415;
Gas: Meters in the top 100 highest volume measurement locations: 104;
Gas: All other active meters: 1,272.
District office: Total;
Inspection activity: Meters inspected;
Oil: Meters in the top 100 highest volume measurement locations: 95;
Oil: All other active meters: 398;
Gas: Meters in the top 100 highest volume measurement locations: 104;
Gas: All other active meters: 1,144.
District office: Total;
Inspection activity: Percentage;
Oil: Meters in the top 100 highest volume measurement locations: 100;
Oil: All other active meters: 96;
Gas: Meters in the top 100 highest volume measurement locations: 100;
Gas: All other active meters: 90.
Source: GAO analysis of OEMM data.
[A] The Lake Charles district office did not oversee any of the 100
top-producing measurement locations in the Gulf of Mexico in fiscal
year 2008.
[B] Goals in the California district differed in 2008 because of the
limited number of meters in the region; specifically, inspectors
conduct site security inspections on 100 percent of royalty meters
annually.
[End of table]
Additionally, in 2008, OEMM met or exceeded its goals for witnessing
10 percent of oil meter provings and 5 percent of gas meter
calibrations. We are not reporting data for witnessing calibrations
from 2004 through 2007 because OEMM expressed concern about the
reliability of data for those years.[Footnote 41]
Table 3: OEMM Liquid Oil and Gas Meter Calibrations Witnessed, Fiscal
Year 2008:
District office: Lake Charles;
Oil: Oil meters: 124;
Oil: Meter provings witnessed: 37;
Oil: Percentage inspected: 30;
Gas: Gas meters: 536;
Gas: Meter calibrations witnessed: 30;
Gas: Percentage inspected: 6.
District office: Lake Jackson;
Oil: Oil meters: 136;
Oil: Meter provings witnessed: 14;
Oil: Percentage inspected: 10;
Gas: Gas meters: 435;
Gas: Meter calibrations witnessed: 23;
Gas: Percentage inspected: 5.
District office: New Orleans;
Oil: Oil meters: 231;
Oil: Meter provings witnessed: 54;
Oil: Percentage inspected: 23;
Gas: Gas meters: 390;
Gas: Meter calibrations witnessed: 39;
Gas: Percentage inspected: 10.
District office: California[A];
Oil: Oil meters: 19;
Oil: Meter provings witnessed: 19;
Oil: Percentage inspected: 100;
Gas: Gas meters: 15;
Gas: Meter calibrations witnessed: 15;
Gas: Percentage inspected: 100.
District office: Total;
Oil: Oil meters: 510;
Oil: Meter provings witnessed: 124;
Oil: Percentage inspected: 24;
Gas: Gas meters: 1376;
Gas: Meter calibrations witnessed: 107;
Gas: Percentage inspected: 8.
Source: GAO analysis of OEMM data.
[A] Goals in the California district differed in 2008 because of the
limited number of meters in the region; specifically, inspectors
witness calibrations on 100 percent of royalty meters annually.
[End of table]
For MMS' Liquid Verification System and Gas Verification System
reconciliation activities, MMS established a goal of resolving 100
percent of the discrepancies it identified between the operator-
reported monthly oil and gas reports and the volumes included on
pipeline meter source documents by mid-2010. MMS staff follow up on
missing documents that operators have not provided, such as the
monthly production allocation schedule report, which are used to
verify volumes reported by operators that are part of a commingling
agreement that include production from nonfederal sources. As of
November 2009, MMS had added additional staff and made progress toward
this goal, but numerous discrepancies remain (see table 4).
Table 4: Progress Toward Resolving Liquid and Gas Volume Discrepancies
and Obtaining Missing Production Allocation Reports, as of November
2009:
Activity: Liquid verification system discrepancies;
Baseline (as of December 2008): 2,427;
Discrepancies remaining: 733;
Percentage reduction: 70.
Activity: Gas verification system discrepancies;
Baseline (as of December 2008): 5,134;
Discrepancies remaining: 3,561;
Percentage reduction: 31.
Activity: Missing production allocation schedule reports;
Baseline (as of December 2008): 419;
Discrepancies remaining: 402;
Percentage reduction: 4.
Source: GAO analysis of MMS data.
[End of table]
BLM Has Not Routinely Met its Production Inspection Goals, Decreasing
Assurances that Oil and Gas are Being Accurately Measured:
For onshore areas, BLM has been unable to consistently meet its
statutory or agency goal for completing production inspections, which
is a key control for ensuring that all production is properly
measured. As we reported in September 2008, BLM's production
inspection data were not entirely reliable, in part due to some
ongoing issues related to the Cobell Indian Trust lawsuit[Footnote 42]
that resulted in the shutdown of BLM's information technology (IT)
systems. As a result, BLM's ability to accurately identify high
priority producing cases was limited, which impacted our ability to
report BLM's production inspection data at the time. Consequently, we
limited our current analysis of BLM data for the seven field offices
we reviewed to determining whether or not cases--both high-and low-
priority--had been inspected at least once every 3 years, in
accordance with BLM's inspection frequency criteria for low-priority
cases. While BLM's production inspection program tracks inspections on
a case level, it is worth noting that a single case may include
anywhere from one to several hundred wells. When a case contains
multiple wells, BLM requires that each production inspection include
inspections of one-fourth of the wells in the case. Our analysis of
BLM data suggests that numerous producing cases have not been
inspected for many years, raising significant uncertainty about
whether the oil and gas are being accurately measured (see figure 7).
Figure 7: Oil Storage Tanks that Had Not Been Inspected for Several
Years:
[Refer to PDF for image: photograph]
Source: GAO.
[End of figure]
Approximately 2 percent, or 198, of active cases between fiscal years
1998 and 2009 requiring an inspection in the six BLM field offices we
reviewed had not been inspected.[Footnote 43] The percentage of
uninspected cases varied by field office, with a low of zero cases in
the Glenwood Springs, Colorado, field office to a high of about 101
cases, in the Carlsbad, New Mexico, field office. Additionally, we
found that about 67 percent of cases had not met BLM's minimum 3-year
inspection requirement. Finally, BLM met or exceeded its minimum 3-
year inspection goals for approximately 31 percent of active cases in
the field offices we visited, though the percentage varied
significantly by field office. For example, the Glenwood Springs,
Colorado, field office had met the minimum goal for about 58 percent
of its cases, whereas both the Carlsbad, New Mexico, and Vernal, Utah,
field offices met the minimum goal for about 27 percent of their cases
as table 5 illustrates.
Table 5: Summary of BLM Production Inspections, Fiscal Years 1998-2009:
Field office: Cases requiring an inspection with no inspection;
Buffalo, Wyoming: 38;
Carlsbad, New Mexico: 101;
Farmington, New Mexico: 38;
Glenwood Springs, Colorado: 0;
Pinedale, Wyoming: 2;
Vernal, Utah: 19;
White River, Colorado[A]: [A];
Total: 198.
Field office: Percentage of cases requiring an inspection with no
inspection;
Buffalo, Wyoming: 2;
Carlsbad, New Mexico: 5;
Farmington, New Mexico: 1;
Glenwood Springs, Colorado: 0;
Pinedale, Wyoming: 1;
Vernal, Utah: 2;
White River, Colorado[A]: [A];
Total: 2.
Field office: Cases not meeting BLM's 3-year minimum inspection goal;
Buffalo, Wyoming: 1,233;
Carlsbad, New Mexico: 1,261;
Farmington, New Mexico: 2,569;
Glenwood Springs, Colorado: 79;
Pinedale, Wyoming: 152;
Vernal, Utah: 601;
White River, Colorado[A]: [A];
Total: 5,895.
Field office: Percentage of cases not meeting BLM's 3-year minimum
inspection goal;
Buffalo, Wyoming: 54;
Carlsbad, New Mexico: 68;
Farmington, New Mexico: 77;
Glenwood Springs, Colorado: 42;
Pinedale, Wyoming: 56;
Vernal, Utah: 71;
White River, Colorado[A]: [A];
Total: 67.
Field office: Cases meeting or exceeding BLM's 3-year minimum
inspection goal;
Buffalo, Wyoming: 1,019;
Carlsbad, New Mexico: 503;
Farmington, New Mexico: 743;
Glenwood Springs, Colorado: 110;
Pinedale, Wyoming: 117;
Vernal, Utah: 228;
White River, Colorado[A]: [A];
Total: 2,720.
Field office: Percentage of cases meeting or exceeding BLM's 3-year
minimum inspection goal;
Buffalo, Wyoming: 44;
Carlsbad, New Mexico: 27;
Farmington, New Mexico: 22;
Glenwood Springs, Colorado: 58;
Pinedale, Wyoming: 43;
Vernal, Utah: 27;
White River, Colorado[A]: [A];
Total: 31.
Field office: Total;
Buffalo, Wyoming: 2,290;
Carlsbad, New Mexico: 1,865;
Farmington, New Mexico: 3,350;
Glenwood Springs, Colorado: 189;
Pinedale, Wyoming: 271;
Vernal, Utah: 848;
White River, Colorado[A]: [A];
Total: 8,813.
Source: GAO analysis of BLM data.
[A] The Interior Office of the Inspector General is currently
evaluating the reliability of inspection data at the White River,
Colorado, field office.
[End of table]
BLM petroleum engineer technicians and production accountability
technicians provided multiple explanations for not completing their
required inspections. First, onshore leases have recently experienced
high levels of drilling; and under BLM's formal inspection strategy,
conducting drilling inspections take priority over conducting
production inspections. In one field office, a BLM official told us
that, historically, the field office's de facto policy was to not
complete production inspections. Second, when BLM revised the volume
criteria downward for high priority cases, the number of cases that
required annual inspections increased, which further reduced
inspection staffs' ability to inspect low priority cases. Third, BLM
officials in the majority of field offices we visited told us they had
challenges with hiring and retaining staff at sufficient numbers to
complete their required inspections. In particular, BLM officials told
us that the low pay, when compared with industry, and the high housing
costs in energy boom towns were major factors affecting hiring and
staff turnover. Finally, the lack of a stable workforce resulted in
multiple attempts to hire new staff. When BLM was successful in hiring
staff, more senior and experienced staff told us that they had to
spend additional time providing on-the-job training, which reduced the
pace of the senior staff inspections. So, despite seeing an increase
in staff at a field office, it is possible that staff will complete
fewer inspections because of the time spent training new staff.
Furthermore, while BLM has not established goals for witnessing
calibrations like OEMM, BLM staff may still conduct these activities.
Our analysis of BLM data shows that BLM staff conducted gas meter
calibrations and oil tank gaugings measurement activities with
decreasing frequency between fiscal years 2004 through 2008 for seven
of the eight BLM field offices we reviewed which had reliable data
(see table 6). Specifically, the frequency with which BLM staff
completed meter calibration activities as part of a production
inspection decreased by 62 percent for the eight field offices we
reviewed between fiscal years 2004 and 2008.
Table 6: Percentage Change in BLM Meter Calibration Activities
Completed, Fiscal Years 2004-2008:
Field office: Buffalo, Wyoming;
Percentage change: -9.
Field office: Carlsbad, New Mexico;
Percentage change: -91.
Field office: Farmington, New Mexico;
Percentage change: -57[A].
Field office: Glenwood Springs, Colorado;
Percentage change: -71.
Field office: Hobbs, New Mexico;
Percentage change: -93.
Field office: White River, Colorado;
Percentage change: [B].
Field office: Pinedale, Wyoming;
Percentage change: -57.
Field office: Roswell, New Mexico;
Percentage change: 0.
Field office: Vernal, Utah;
Percentage change: -69[A].
Field office: Total;
Percentage change: -62.
Source: GAO analysis of BLM data.
[A] According to BLM officials, the reliability of data provided for
these offices may have been affected for several years because of
issues related to the impact the Cobell lawsuit had on BLM's IT
systems. Specifically, some data at the inspection activity level may
not have been entered into the system between 2004 and 2008 because of
system shutdowns. Therefore, numbers presented here, while
representative of what is in the system, may be undercounts.
[B] The Interior Office of the Inspector General is currently
evaluating the reliability of inspection data at the White River,
Colo., field office.
[End of table]
Petroleum engineer technicians from five of the nine field offices we
spoke with did not believe that they were witnessing a sufficient
number of gas meter calibrations. When asked why more calibrations
were not witnessed, staff typically said there was either insufficient
staff or time. For petroleum engineer technicians in the four BLM
field offices who felt a sufficient number of calibrations were
witnessed, staff stated that they had infrequently identified meter
calibration problems and, therefore, believed it was an area of lower
concern.
Analysis of tank gauging inspection data also shows a general decline
in the number of tank gaugings entered by BLM petroleum engineer
technicians in BLM's database. From fiscal years 2004 through 2008,
tank gauging activity codes were entered with decreasing frequency for
seven of the eight BLM field offices we reviewed for which we had
reliable data (see table 7). Overall, the frequency with which BLM
staff completed meter calibration activities as part of a production
inspection decreased by 33 percent for the eight field offices we
reviewed between fiscal years 2004 and 2008.
Table 7: Percentage Change in BLM Tank Gauging Calibration Activities
Completed, Fiscal Years 2004-2008:
Field office: Buffalo, Wyoming;
Percentage change: -44.
Field office: Carlsbad, New Mexico;
Percentage change: -55.
Field office: Farmington, New Mexico;
Percentage change: 240[A].
Field office: Glenwood Springs, Colorado;
Percentage change: -57.
Field office: Hobbs, New Mexico;
Percentage change: -67.
Field office: White River, Colorado;
Percentage change: [B].
Field office: Pinedale, Wyoming;
Percentage change: -74.
Field office: Roswell, New Mexico;
Percentage change: -50.
Field office: Vernal, Utah;
Percentage change: -50[A].
Field office: Total;
Percentage change: -33.
Source: GAO analysis of BLM data.
[A] According to BLM officials, the reliability of data provided for
these offices may have been affected for several years because of
issues related to the impact the Cobell lawsuit had on BLM's IT
systems. Specifically, some data at the inspection activity level may
not have been entered into the system between 2004 and 2008 because of
system shutdowns. Therefore, numbers presented here, while
representative of what is in the system, may be undercounts.
[B] The Interior Office of the Inspector General is currently
evaluating the reliability of inspection data at the White River,
Colorado, field office.
[End of table]
According to BLM petroleum engineer technicians from the nine field
offices we spoke with, representatives from five of the offices told
us that they were not completing a sufficient number of tank gaugings
and provided several reasons why more were not completed. Staff from
two of the field offices stated that a limiting factor in completing
additional tank gaugings was a lack of tank gauging equipment, whereas
staff from another field office explained that they had insufficient
staff and competing priorities. Staff from one field office who
concluded that they were completing a sufficient number of tank
gauging activities explained that they were consistently completing
them on all cases with tanks, while staff from one other field office
said that the office had never identified under-reported production
from completing the tank gauging activity.
Interior's Production Accountability Inspection Programs Do Not
Sufficiently Address Key Factors Affecting Gas Measurement Accuracy:
Interior's production accountability inspection programs do not
sufficiently address six key factors that may affect measurement
accuracy: (1) witnessing gas sample collections, (2) verifying BTU
values are correctly reported, (3) witnessing orifice plate
inspections, (4) assessing impacts of liquids in gas streams, (5)
addressing low differential pressure, and (6) inspecting meter tubes.
* Witnessing gas sample collections. Interior has not established
goals for witnessing gas samples collected by industry. Because the
heating value of gas--measured in BTU--is directly related to the
royalties paid on the gas, any contamination or mishandling of the
sample has the potential to lead to an incorrect BTU analysis.
According to BLM calculations, a 10 percent error in reported heating
value will result in a 10 percent error in royalties due. With onshore
royalties valued at $2 billion per year, a 1 percent error in reported
heating value would lead to a $20 million error in royalties paid.
Current regulations require industry to take gas samples annually for
onshore, and semiannually for offshore. However, one member of BLM's
Gas Measurement team expressed concerns about how companies were
collecting these gas samples in the field, and how those samples were
subsequently handled and transported. Currently, neither BLM nor OEMM
have regulations in place stating how or where a sample is to be
taken, how a sample is to be analyzed, or how heating value should be
reported. Additionally, neither BLM nor OEMM have established goals
for witnessing gas sample collections, or tracking the number of
samples the agencies may have witnessed during the course of an
inspection. Furthermore, procedures for collecting gas samples were
only recently incorporated into BLM's training courses, meaning that
some BLM staff may not have the knowledge required to identify
incorrect gas sampling techniques.
* Verifying BTU values are correctly reported. Interior only recently
clarified how companies should report onshore gas BTU values, but does
not sufficiently verify that operator-reported BTU values are correct.
In December 2007, the Royalty Policy Committee's Subcommittee on
Royalty Management recommended that Interior establish consistent
guidelines for how companies report BTU values. Until 2009, BLM did
not have a formal policy for how operators were to report BTU values.
Instead, BLM informally carried forward a 1980 policy from the U.S.
Geological Survey--which oversaw oil and gas activities and royalty
collections before BLM and MMS assumed responsibility for overseeing
oil and gas production. This policy allowed operators to report the
BTU value with an assumed water content, as gas may contain water
vapor. According to BLM documents, this assumption has resulted in an
automatic reduction as high as 1.74 percent in the BTU value, which
corresponds to approximately a 1.74 percent decrease in royalty
payments. On July 30, 2009, BLM issued an instruction memorandum to
its field office staff defining its policy for reporting BTU values.
[Footnote 44] The policy requires that all BTU values in the monthly
production report be reported on a dry basis--without an assumed water
content--unless the gas sample is analyzed for water content. In that
case, the actual BTU value should be reported. BLM can verify this
value when conducting a limited number of annual record reviews by
comparing BTU values from gas analysis reports with the BTU value on
the operator-reported production report. BLM estimates that this
policy change may increase royalties up to $35 million per year.
However, BLM had not formally communicated this policy change to
companies producing onshore gas, as of September 2009. As a result,
companies may continue to erroneously submit incorrect BTU values,
thereby placing royalty collections at risk. Additionally, the same
December 2007 Subcommittee on Royalty Management report included a
recommendation that Interior develop a means to systematically compare
reported BTU values on the operator-reported monthly production report
with BTU values from lab analyses. According to MMS officials, in
early 2010, they are planning to incorporate BTU comparisons into
their Gas Verification System. However, a BLM official told us that
comparisons will continue to be made on a limited basis during in-
depth record reviews completed by production accountability
technicians and that there is no plan to increase these reviews.
* Witnessing orifice plate inspections. Neither BLM nor OEMM has
established specific goals for witnessing orifice plate inspections, a
critical factor for ensuring accurate gas measurement (see figure 8).
While BLM has a regulatory requirement for the operator to inspect the
orifice plate semiannually, it has no goal for BLM inspectors to
witness this activity. According to BLM petroleum engineer technicians
in multiple field offices, orifice plates are generally inspected
during a meter calibration; however, BLM is unable to readily provide
summary data from its database on the number of orifice plates
inspected, the condition of the plates, or whether the plates were
replaced. OEMM lacks a regulatory requirement for operators to inspect
the condition of orifice plates with a specified frequency, and also
lacks a goal for inspectors to physically witness the inspection of
the plate, although OEMM officials and staff told us that inspectors
routinely examine the orifice plate during the gas meter calibrations
that they witness, and that conducting orifice plate inspections was
included in a 2009 OEMM meter inspection training course. Similarly,
OEMM does not track data in its database on the number of orifice
plates inspected, the condition of orifice plates, or whether a plate
was replaced.
Figure 8: BLM Petroleum Engineer Technician Inspecting an Orifice
Plate:
[Refer to PDF for image: photograph]
Source: GAO.
[End of figure]
* Assessing impacts of liquids in gas streams. Neither BLM nor OEMM
has a policy or an inspection activity for assessing the effects of
liquids in gas on gas measurement. According to one BLM official, the
impact of liquids in gas on measurement accuracy has largely been
ignored by federal regulators, although the effect could be
significant. Petroleum engineers at four of the seven BLM field
offices we visited stated that they generally consider the impact of
liquids on measurement; however, BLM does not have sufficient
regulations or guidance on this issue and a BLM official told us that
BLM does not currently have the authority to require the installation
of additional equipment that would remove liquids from the gas stream.
One petroleum engineer explained that contracts between the operator
and the pipeline company include a maximum limit on liquids in the gas
stream and that, if the limit is exceeded, the pipeline company will
refuse to transport the gas. However, most of BLM's points of
measurement are at the well head, where liquids in gas may be more
prevalent. Similarly, an OEMM official told us that OEMM does not
require petroleum engineers to determine the extent to which any
liquids may affect gas measurement. However, the official noted that a
measurement system without any equipment to remove liquids prior to
measurement would not be approved, but that there were no requirements
to assess whether this equipment would sufficiently remove liquids.
Similarly, offshore inspectors are not required to examine whether
liquids are present in gas meters--but some OEMM inspectors told us
that they would likely notice the presence of liquids.
* Addressing low differential pressure. Interior has not fully
addressed the impact of low differential pressures on gas measured by
orifice meters. Typically, wells are calibrated for a continuous
operating flow; however, there can be wide fluctuations in gas flow
over time, resulting in extreme shifts in differential pressure--
either raising it or lowering it. According to BLM officials,
accurately measuring gas under low-pressure conditions can be
difficult. Operators may size the orifice plates and calibrate the
meters to accurately measure the gas during times of high pressure.
This, in turn, limits the ability of the meters to accurately measure
gas at low pressure. To date, BLM does not have regulations
specifically addressing the complexities that arise with measuring gas
under low pressure. While BLM has developed a tool--an uncertainty
calculator--which allows staff to input various measurement
parameters, including the differential pressure, and determine whether
the measurement uncertainty exceeds BLM's 3 percent limit, we found
that staff are not consistently using this important tool. Moreover,
according to a BLM official, an industry group has recently completed
a study on the impact of low differential pressure on gas measurement
with results suggesting that at lower differential pressures,
measurement uncertainty increases. However, according to a BLM
official, BLM has not fully reviewed the study, though its results
could inform a policy on gas measurement at low differential pressures.
* Inspecting meter tubes. Interior has not established goals for
inspecting meter tubes, despite the potential impact on measurement
that could result. According to BLM's 1994 draft gas measurement
regulations, proper meter tube condition is essential for accurate
measurement. These draft regulations established a requirement for
operators to inspect the meter tubes once every 5 years; however, the
regulations were not finalized, and BLM never implemented that
requirement. Furthermore, BLM does not currently include meter tube
inspections as a component of its inspection program. Similarly, OEMM
has no regulatory requirement for inspecting meter tubes.
Limited Oversight, Gaps in Staffs' Critical Measurement Skills, and
Incomplete Tools Hinder Interior's Ability to Manage its Production
Verification Programs:
Interior's management of its production verification programs are
hindered by its (1) limited and inconsistent oversight of its oil and
gas production accountability programs; (2) difficulties in hiring,
training, and retaining staff; and (3) longstanding challenges with
providing inspection staff with key information technology tools to
allow them to more efficiently complete their production inspections.
Interior Has Exercised Limited and Inconsistent Oversight of its Oil
and Gas Production Accountability Programs:
Interior has not completed reviews of its production accountability
programs' internal controls in recent years. Moreover, Interior's more
decentralized organizational structure for its onshore inspection
program, when compared to its offshore program, raises the risk of
inconsistent program oversight. Finally, Interior's onshore oversight
of production inspection data entry and key engineering decisions are
less robust when compared with its offshore controls.
Interior Has Not Recently Conducted Internal Reviews of Its Production
Verification Internal Controls:
Interior has exercised limited programmatic oversight of key areas of
its oil and gas production verification programs. Like all federal
agencies, Interior is required to conduct ongoing internal reviews of
its internal controls by both the Federal Managers' Financial
Integrity Act (FMFIA)[Footnote 45] and OMB Circular-123, Management's
Responsibility for Internal Control. However, Interior has made
inconsistent and, in some cases, incomplete efforts to meet this
requirement.
In accordance with this internal review requirement, senior management
in both BLM and MMS are to annually determine which programs should be
subject to formal review in order to supplement management's judgment
as to the adequacy of internal controls and to ensure that adequate
resources are allocated to evaluate those controls, among other
responsibilities. Interior requires both BLM and MMS to annually
create an Internal Control Review Plan that (1) summarizes their
programs, (2) identifies the relative risk ranking of each of the
programs, and (3) establishes the type of control evaluation to be
conducted and the year the evaluation will be completed. However, BLM
and MMS have undertaken inconsistent approaches to meeting these
requirements.
BLM has not conducted a timely review of its production accountability
program and has recently lowered the risk associated with its
production verification program, despite mounting evidence that the
program is placing at risk Interior's ability to ensure that the
federal government is accurately collecting revenue. In our review of
BLM's completed internal control reviews, we found that it had not
conducted any reviews related to production verification in the
western United States since 2000. Moreover, while BLM had planned to
complete a review in 2009, it was canceled in light of ongoing reviews
being conducted by GAO and Interior's Inspector General. According to
BLM's 2009 - 2011 Internal Control Review Plan, no subsequent
production verification reviews are planned. Additionally, BLM has
lowered its assessment of the risk of the program, despite reports
issued by GAO, Interior's Inspector General, and the Royalty Policy
Committee's Subcommittee on Royalty Management, that pointed out
weaknesses in internal controls within Interior's oil and gas
production and royalty collection programs. According to federal
standards on internal controls, monitoring of internal reviews should
include policies and procedures for ensuring that findings of audits
and other internal reviews are promptly resolved.[Footnote 46]
Additionally, Interior guidance requires that such reports should be
given appropriate consideration in determining risk. In fiscal year
2009, BLM lowered the risk rating of its oil and gas program from
medium to low. According to a BLM official, risk ratings are assigned
through a subjective evaluation based on program management knowledge.
In reviewing supporting risk assessment documentation, we found
several questionable assumptions in the years leading up to the risk
determination made in the most recent plan. In reviewing supporting
BLM oil and gas program risk assessment documentation, we found that
BLM documents ranked the production accountability program as a low
risk area for three reasons. First, BLM officials determined there was
a low risk of lost potential revenue collection due to incorrect
production reporting, despite the fact that Interior was missing tens
of thousands of monthly production reports from operators.
Specifically, BLM assumed that potential losses from not submitting
production reports may only be 0.1 percent of royalties, which, given
that onshore production accounted for approximately $2 billion, the
losses might amount to $2 million. Second, BLM officials determined
that there was a low risk of not completing its production inspections
due to its workforce levels and the capability of the workforce.
Finally, BLM officials concluded that due to significant efforts over
the past several years to improve internal controls, the production
accountability program had a low level of risk due to a lack of
internal controls.
Similarly, MMS has not completed any reviews of production
verification related internal control activities in 5 years. While MMS
completed one internal control review of OEMM's offshore inspection
program in 2004, this review examined many aspects of the inspection
program, not just those addressing production verification. The key
findings of the review were that OEMM needed more clearly defined
inspection strategies, and that about 70 percent of inspection staff
had taken some training in measurement. According to MMS's 2009-2011
Internal Control Review Plan, OEMM's production verification program
is scheduled to be reviewed in 2011, although the scope of this review
has yet to be planned. Finally, in contrast to BLM's low risk status
for its production verification programs, MMS has assigned a medium
risk status for both its offshore inspection program and its
production verification program, although MMS officials were unable to
provide us with supporting documentation for how they determined the
risk level.
Interior's Decentralized Approach to Onshore Oversight, When Compared
to its More Centralized Approach to Offshore Oversight, May be
Reducing Program Effectiveness:
Interior has undertaken very different approaches to the oversight of
the production inspection programs for onshore leases and offshore
leases. BLM's production inspection program is decentralized, with
field offices being granted a great deal of autonomy for making key
decisions. In contrast, OEMM's Gulf of Mexico Regional Inspection
Program is more centrally managed.[Footnote 47] The difference in
oversight approaches may lead Interior to miss opportunities to
identify best practices; deploy such tools across Interior's
operations; and, as a result, place program oversight at risk.
Agencies are generally provided the opportunity to determine how best
to delegate responsibilities and conduct supervision. However, as a
general matter, effective organizational structures should facilitate
the flow of information needed for decision making to appropriate
staff throughout the agency and provide for reasonable mechanisms to
ensure that agency staff are appropriately supervised. An agency's
structure may be centralized or decentralized given the nature of the
organization's operations, but the management should be able to
clearly articulate the considerations and factors taken into account
in balancing the degree of centralization versus decentralization.
According to Federal Standards for Internal Controls, key among the
considerations for determining effective organizational structures are
ensuring that clear internal reporting relationships have been
established, which effectively provide managers information they need
to perform their job.[Footnote 48]
BLM's Inspection and Enforcement Program--which includes production
inspections--for onshore leases is relatively decentralized (see
figure 9). While BLM has created a number of mechanisms for
coordinating the operations of the production inspection program
across field and state office jurisdictional boundaries, key
supervisory functions remain largely under the control of field
offices where, according to some BLM officials, supervisors have
limited understanding of the jobs they are supervising. BLM's
Inspection and Enforcement Program is currently coordinated at the
national level by two national lead coordinators, one of whom
coordinates program issues through quarterly teleconferences with
state coordinators. According to one of the national coordinators,
much of the inspection program oversight has been delegated to state
coordinators who are responsible for conducting periodic reviews of
inspections completed by field office inspection staff and
coordinating among the state's field offices. This national
coordinator further told us that reviews completed by the state
coordinators are not systematically reviewed at the national level.
Under the federal standards for internal control, federal agencies
should employ internal control activities, such as top-level review,
to help ensure that management's directives are carried out and to
determine if the agencies are effectively and efficiently using
resources.[Footnote 49] According to several state coordinators, their
reviews--which are not standardized--may include reviewing data in
BLM's inspection database or participating with petroleum engineer
technicians in conducting inspections in the field. Should a state
coordinator identify areas of concern during these reviews, the state
coordinator does not have authority to require that petroleum engineer
technicians or production accountability technicians modify their
work, as neither the national or state coordinators have supervisory
authority over the BLM staff at the field office level. Rather, BLM's
petroleum engineer technicians and production accountability
technicians, in some field offices, report to and are evaluated at the
field office level by BLM field office managers[Footnote 50] who,
according to BLM staff, do not in all instances have a strong
background in oil and gas operations and production verification.
Furthermore, while BLM offers an "Oil and Gas Training for Managers"
course, managers are not required to take it. Therefore, state
coordinators must relay any findings or concerns about an individual's
performance to the field office manager, though there is no
requirement that the field office manager act upon any findings.
Several state coordinators told us that providing input on inspectors'
performance to field office managers has been met with varying degrees
of success. For example, one state coordinator stated that the field
office managers were generally unreceptive to input on their staffs'
job performance; whereas, another state coordinator explained that
field office managers had been accommodating to their feedback on
petroleum engineer technicians' or production accountability
technicians' performance. The national and state coordinators' lack of
supervisory authority may be putting the inspection and enforcement
program at risk of diminished effectiveness.
Figure 9: GAO Representation of BLM's Production Verification
Inspection and Enforcement Organizational Structure:
[Refer to PDF for image: organization chart]
National Inspection and Enforcement Coordinator (has advisory
consultation responsibilities with all entities):
BLM State Office Director (has direct supervisory authority over the
following):
* State Inspection and Enforcement Coordinator;
* BLM Field Office Manager;
- PE;
- PET;
- PAT.
Source: GAO.
[End of figure]
In contrast, OEMM's Gulf of Mexico region inspection program is more
centralized and systematic in its oversight of its five district
offices (see figure 10). OEMM's inspection program is overseen
directly by the supervisor of district operations, who has direct
supervisory authority over each of the five district office managers.
The district managers, who are typically petroleum engineers,
supervise the district's chief inspector who, in turn, oversees the
lead inspectors and other district inspectors. Furthermore, OEMM has a
regional inspection coordinator whose role is to, in part, ensure that
inspection activities are consistent across the OEMM district offices.
In fulfilling these duties, the regional inspection coordinator has
weekly discussions with lead inspectors in each of the five district
offices and also holds a monthly teleconference among all supervisory
inspection staff, for further coordination. In addition, the regional
inspection coordinator conducts yearly consistency reviews of each
district, which involve observing inspection personnel performing
inspections, interviewing district inspection personnel, and reviewing
inspection statistics. Findings and recommendations from the
consistency reviews are documented in a standardized report. District
offices are required to develop an action plan within 15 days to
address any shortcomings identified during the review. If a district
office fails to respond to the recommendations--which, according to
the regional inspection coordinator, has not yet happened--then,
regional management would be notified, according to the regional
official who prepares these reports.
Figure 10: GAO Representation of OEMM's Production Verification and
Inspection Organizational Structure:
[Refer to PDF for image: organization chart]
OEMM Regional Manager (has direct supervisory authority over the
following):
* Regional Supervisor for Production and Development;
* Petroleum Engineers, Surface Commingling and Production Management;
* Regional Manager of District Operations (has direct supervisory
authority over the following):
* District Office Managers;
* District Office Inspectors.
* Regional Inspection Coordinator (coordinates inspections for the
regional manager with District Office Inspectors).
Source: GAO.
[End of figure]
Interior Has Exercised Limited Oversight of its Onshore Inspection
Data and Engineering Approvals When Compared with Its Offshore
Oversight:
Our review also found that Interior's oversight of inspection data
varied significantly between BLM and OEMM, with BLM exercising limited
oversight of its onshore inspection data and, thereby, increasing the
risk of inaccurate inspection data. Typically, BLM petroleum engineer
technicians document the results of their inspections on BLM official
forms and, later, enter those results in BLM's inspection database.
Except for situations where a petroleum engineer technician has not
completed the required training, BLM does not require that inspection
forms be reviewed to ensure that inspections were properly conducted
or that the results of those inspections were properly documented in
its database. Furthermore, when BLM petroleum engineer technicians
find violations in the field, they may issue incidents of
noncompliance without supervisory review, unless the petroleum
engineer technician has not completed the required training.
We found BLM's controls over its production inspection data were
insufficient to ensure accurate data. In examining BLM's controls over
inspection data, we (1) reviewed a nongeneralizable sample of 43 hard
copy production inspection files for inspections completed between
fiscal years 2004 and 2008 for four of the seven field offices we
visited[Footnote 51] and (2) analyzed all BLM production inspection
data for fiscal years 2004 through 2008 from the nine field offices we
reviewed. We found several errors, including discrepancies between
what was documented in the hard copy files and what was entered in
BLM's database and inconsistencies in how BLM's chart verification
production inspection activity was conducted to ensure accurate gas
measurement. Additionally, we found errors in how specific production
inspection activities were entered into BLM's database.
Specifically, our review of 43 hard copy files identified instances
where inspection activities documented in BLM's database were not
supported by documents in the hard copy files and that BLM staff were
inconsistently completing the chart verification production inspection
activity--an activity to independently verify the electronic flow
computers' gas volume calculations. BLM's internal guidance for
documenting inspections requires that, without exception,
documentation gathered during the inspection be incorporated into the
hard copy files. Yet, we identified instances where BLM's database
indicated that a particular activity had been completed, but no
supporting documentation was included in the hard copy file. For
example, we identified several instances where BLM's database
indicated that a meter calibration activity had been completed, yet no
calibration report was included in the hard copy file. We further
found other instances where BLM staff were unable to locate hard copy
files, and one instance where a hard copy file contained no
information.
Our hard copy file review also found instances where BLM staff were
inconsistently completing the chart verification production inspection
activity--an activity to verify the reasonableness of the monthly
operator-reported volumes and that the electronic flow computer is
functioning properly. We found some instances where BLM staff compared
the operator-submitted monthly gas volumes, divided by the number of
days in the month to the daily gas volumes displayed on the well's
electronic flow computer to determine whether they are were reasonably
close. Alternatively, we found that other BLM staff used parameters
displayed in the electronic flow computer to independently recalculate
the volumes and compare those volumes to the volume displayed on the
electronic flow computer. Additionally, one BLM petroleum engineer
technician told us he used BLM's Gas Measurement Uncertainty
Calculator, which is used to verify whether gas is measured within an
overall 3 percent uncertainty range, when completing a chart
verification inspection activity, although we found no evidence of
this in the hard copy files we selected. Furthermore, though BLM's
internal guidance for documenting inspections states that precise and
clear documentation allows anyone reviewing the file to verify the
inspection type and all completed activities associated with that
inspection, we found that hard copy files in two of the four field
offices were disorganized and not easily interpreted. For example, in
several of the files, it was not possible to determine what inspection
actions were completed without the assistance of BLM officials.
Finally, our analysis of all production inspection data recorded in
BLM's database for fiscal years 2004 through 2008 for the nine field
offices we reviewed, found that approximately 38 percent of the
production inspections appeared to be coded incorrectly, suggesting
that BLM does not have sufficient controls in place to ensure that
production inspections are being conducted or entered into its
database in accordance with agency policy. Specifically, BLM guidance
on entering data for production inspections states that duplicate
inspection activities should not be entered for the same inspection
unless an oil or gas volume discrepancy was found; yet approximately
10 percent of inspections we analyzed included duplicate entries for
inspection activities that are not associated with volume
discrepancies. For example, a single production inspection from fiscal
year 2004 had site security coded nine times and surface protection
coded ten times which, according to BLM's database coordinator, is
incorrect. Further, an additional 28 percent of production inspections
recorded in BLM's database appeared to be erroneous because they did
not include all four required inspection activities. For example,
production inspections for producing cases should have four associated
inspection activities--record review, surface protection, site
security, and at least one measurement-related activity. However, we
found numerous examples where the inspections were missing one or more
of these activities (see table 8).
Table 8: BLM Production Inspection Activity Data, Fiscal Years 2004-
2008:
Total production inspections: Production inspections recorded in
accordance with BLM criteria;
Number: 6,443;
Percentage: 62.
Total production inspections: Production inspections with erroneous
duplicate inspection activities and/or potential missing inspection
activities;
Number: 994;
Percentage: 10.
Total production inspections: Production inspections with missing
inspection activities and no duplicate inspection items;
Number: 2,893;
Percentage: 28.
Total production inspections: Total;
Number: 10,330;
Percentage: 100.
Source: GAO analysis of BLM data.
[End of table]
In contrast, OEMM has stronger supervisory controls for inspection
data, providing greater assurance these data are accurate. Inspectors
document the results of their inspections on official OEMM forms,
specifying the kinds of inspections completed; which meters were
observed; and what, if any, violations were documented. After the
inspections are completed, one or more supervisory inspectors review
the inspection form, and then give it to a clerical worker for
recording in OEMM's database. If violations are found, they are issued
during the inspection and are reviewed by supervisory inspectors.
In examining OEMM's controls over inspection data, we also reviewed a
nongeneralizable sample of 20 hard copy production inspection files
for inspections completed between fiscal years 2007 and 2008 for two
of the four district offices we reviewed.[Footnote 52] We found one
instance where what was documented in the OEMM hard copy file did not
match what was entered in OEMM's database regarding one of the two
inspection activities--meter calibration witnessing. In the other 19
instances, we found that the hard copy inspection files matched what
was in OEMM's database. We also found that the files were complete, in
that they contained the required documentation for these inspections.
Regarding engineering approvals, there are also inconsistent
supervisory controls between onshore and offshore programs, as well.
We found that production measurement related engineering approvals
completed by BLM petroleum engineers are typically not reviewed by
other engineers. In many of the field offices we visited, petroleum
engineers have approval authority for both variances of measurement
regulations, as well as commingling and allocation agreements. These
engineering approvals are significant and can greatly impact
production verification and accountability for a number of years. Yet,
BLM does not have controls in place to ensure a reasonable level of
consistency in applying these policies. According to BLM petroleum
engineers we spoke with, their engineering approvals have not been
routinely reviewed, and according to one BLM official, the effect of
poor decisions could have long-lasting impacts. For offshore
production, OEMM engineers who approve systems for measuring oil and
gas are centralized in one of OEMM's three regional offices: the Gulf
of Mexico, Pacific, and Alaska.[Footnote 53] The OEMM engineering
approvals of proposed measurement systems and commingling arrangements
are reviewed twice--first by a supervisory engineer, and then by the
section chief, who signs and issues the final approval.
Interior Lacks Staff with Critical Production Verification Skills
because of Difficulties in Hiring, Training, and Retaining Staff,
Placing Production Verification Efforts at Risk:
Interior's production verification program staff lack critical skills
because of challenges in hiring experienced staff, not consistently
providing the appropriate training for these staff, and high turnover
in key production verification positions, according to agency
officials. Onshore, agency officials told us that Interior has
experienced challenges in hiring staff for its petroleum engineer,
petroleum engineer technician, and production accountability
technician positions; providing these staff with timely and ongoing
training; and retaining these staff over the long term. Furthermore,
while Interior's staffing challenges are less pronounced for its
offshore program, there have been fewer difficulties in hiring and
retaining staff, the agency has not consistently offered its engineers
or inspectors a formal training program on oil and gas measurement
(see table 9).
Table 9: Summary of Hiring, Training, and Retention Issues Identified
for Interior Production Verification Staff:
BLM:
Petroleum engineer;
Hiring: [Check];
Training: [Check];
Retaining: [Check].
Petroleum engineer technician;
Hiring: [Check];
Training: [Check];
Retaining: [Check].
Production accountability technician;
Hiring: [Check];
Training: [Check];
Retaining: [Check].
OEMM:
Petroleum engineer;
Hiring: [Check];
Training: [Check];
Retaining: [Empty].
Inspector;
Hiring: [Check];
Training: [Check];
Retaining: [Check].
MMS:
Liquid and Gas verification system staff;
Hiring: [Empty];
Training: [Empty];
Retaining: [Empty].
Source: GAO analysis.
[End of table]
Interior Has Key Weaknesses in Hiring, Training, and Retaining Staff
in Critical Measurement Positions, Reducing Assurance that Oil and Gas
Are Accurately Measured:
Interior has weaknesses in key onshore and offshore positions critical
for providing assurances that oil and gas are measured accurately due
to challenges in hiring, training, and retaining these staff. Under
federal standards for internal controls, federal agencies are to
maintain effective management of their workforce in order to achieve
results. Management should ensure that skill needs are continually
assessed and that the organization is able to obtain a workforce that
has the required skills that match those necessary to achieve
organizational goals. Training should be aimed at developing and
retaining employee skill levels to meet changing organizational needs.
[Footnote 54] Specific to oil and gas activities, FOGRMA requires that
the Secretary of the Interior establish and maintain adequate programs
for the training of all such authorized representatives in methods and
techniques of inspections and accounting that will be used in the
implementation of the law.[Footnote 55]
According to both BLM and OEMM staff, hiring for the following key
positions has been difficult in recent years because of low pay
relative to comparable private sector jobs: BLM and OEMM petroleum
engineers, BLM petroleum engineer technicians, BLM production
accountability technicians and OEMM inspectors. For example, BLM's 2008
- 2013 Human Capital Plan identifies both the petroleum engineer and
petroleum engineer technician positions as critical to its mission and
identifies high salaries offered by industry and a lack of affordable
housing in energy "boom towns" as factors that make recruiting
employees for these positions difficult. Additionally, a 2007 study
conducted by BLM on position classifications for its petroleum
engineers and petroleum engineer technicians found, in many cases, a
significant pay disparity between federal employees and the private
sector, though the amount varied by location. For example, the report
found that starting salaries for BLM petroleum engineers entering the
workforce for the first time were between $10,000 and $35,000 less per
year than in the private sector. Furthermore, while some BLM officials
acknowledged benefits to government employment, including job
stability, this benefit has not been sufficient to consistently
attract qualified candidates. Additionally, BLM officials told us that
several areas where BLM has field offices also have high costs of
living, including in Pinedale, Wyoming, and Glenwood Springs,
Colorado. In both of these locations, BLM officials told us that they
had experienced difficulties in hiring staff at current salary levels
because housing costs in these localities were such that finding
affordable housing was extremely difficult. Offshore, OEMM officials
told us that hiring petroleum engineers and inspectors had been
difficult, but less so for engineers recently because of the economic
downturn. OEMM officials told us that the private sector was able to
offer significantly higher salaries for inspectors, compared with
OEMM. However, one benefit OEMM offers is that, unlike many private
sector offshore jobs, which require extended stays on offshore
platforms, OEMM inspectors infrequently spend more than one day on a
platform.
Neither BLM nor OEMM have consistently provided training necessary for
performing official job duties of BLM and OEMM petroleum engineers,
BLM petroleum engineer technicians, BLM production accountability
technicians, and OEMM inspectors. For example, BLM and OEMM petroleum
engineers are not required to take measurement training or other
courses related to production verification. Specifically, BLM's
petroleum engineers, who generally have responsibility for approving
measurement methods not authorized under current regulations and
reviewing and approving commingling agreements, do not have any
required initial measurement training or subsequent annual maintenance
training requirements. Similarly, OEMM petroleum engineers do not have
specific measurement training requirements; instead, relying on an
annual training plan that is developed according to individual topic
preferences. Furthermore, BLM has not provided its petroleum engineer
technicians and production accountability technicians with the
necessary training. For example, BLM offers a core curriculum for its
petroleum engineer technicians, requiring that they pass a six module
training course, obtain official BLM certification, and then be
recertified once every 5 years to demonstrate continued proficiency;
however, BLM has not offered a recertification course since 2002.
While BLM has, on occasion, offered training for its production
accountability technicians, both a BLM training coordinator and staff
we spoke with stated that it was not sufficient for fully
understanding and performing the full range of job responsibilities.
In contrast, OEMM does not offer its inspectors a core inspection
training curriculum, though there is a requirement for completing 60
hours of training. In 2009, the Gulf of Mexico OEMM region also
provided its inspectors with a newly implemented measurement class.
However, while OEMM officials at four district offices we spoke with
acknowledged that measurement issues were complex, OEMM does not
systematically evaluate the extent to which inspectors have
measurement knowledge, nor are there requirements for inspectors to
take specific measurement training. As a result, OEMM does not have an
effective system to evaluate whether its inspection staff lacks
important measurement expertise.
Finally, Interior has struggled with high turnover rates in its
onshore production verification positions. Specifically, we found that
turnover rates for BLM's petroleum engineers, petroleum engineer
technicians, and production accountability technicians were generally
high and, according to BLM officials, were negatively impacting
program implementation. Furthermore, we obtained and analyzed BLM
human capital data and found that, for example, the overall turnover
rate for petroleum engineers was between 33 and 100 percent between
fiscal years 2004 through 2008 for the eight field offices we
examined.[Footnote 56] Similarly, the overall turnover rates for the
same period for petroleum engineer technicians ranged between 30 and
83 percent for 7 of the 9 field offices we examined; with the
remaining two offices having turnover rates of 22 percent or less.
Finally, overall turnover rates for production accountability
technicians were also generally high, with 8 of the 9 field offices
having turnover rates of 50 percent or more between fiscal years 2004
and 2008.[Footnote 57] According to BLM officials, staff turnover is
impeding the production verification program in two areas. First,
staff turnover results in the loss of institutional knowledge of the
program. Second, BLM must direct its resources toward attracting and
hiring staff, then have more senior staff provide on-the-job training
for the new staff, which limits the senior staffs' capacity for
completing their own work. Finally, BLM's 2008 - 2013 Human Capital
report suggests that turnover will continue to be a challenge as it
estimates that approximately 25 percent of its petroleum engineers and
47 percent of its petroleum engineer technicians will be eligible to
retire by 2013. In contrast, OEMM petroleum engineers and inspectors
generally had overall turnover rates less than BLM for fiscal years
2004 through 2008. For example, overall turnover rates for OEMM
petroleum engineers in the OEMM Gulf of Mexico and Pacific regional
offices--which are responsible for measurement approvals for the four
district offices we reviewed--did not have overall turnover rates
exceeding 30 percent between fiscal years 2004 and 2008. Additionally,
we found that overall turnover rates for OEMM inspectors varied
between 27 and 44 percent between fiscal years 2004 and 2008. For
example, the California district office had an overall rate of 44
percent turnover, based on the four inspectors who left the position
over those 5 years; the Lake Jackson, Texas, district office had an
overall rate of 27 percent turnover. Finally, according to MMS
officials, MMS has added a significant number of staff to its Liquid
and Gas Verification system to help address current backlogs. Current
provisions in federal employment regulations allow agencies to adjust
pay rates to be more competitive with the private sector. For example,
federal agencies may increase pay by increasing the General Schedule
grade of the position, requesting special pay rates for difficult to
fill positions, and providing bonuses for hiring and retention.
However, while BLM has only recently begun to use some financial
incentives for recruiting and retaining staff, BLM has not adjusted
its overall pay structure for these positions and turnover rates
remain high (see appendix IV for additional information on human
capital challenges within key measurement positions).
Interior's Longstanding Efforts to Implement Two Key Technologies to
Improve Production Verification Are Behind Schedule and Years From
Widespread Implementation:
Interior's efforts to develop (1) software to allow inspection staff
to remotely monitor gas production, and (2) a mobile computing
platform for inspection staff to enter inspection results while in the
field, are behind schedule and, according to agency staff, years from
widespread use.
Interior's 10-Year Effort to Obtain Continuously Updated Gas
Production Data Have Shown Few Results:
BLM's Remote Data Acquisition for Well Production (RDAWP) program--a
program designed to allow BLM staff to monitor gas production in near
real-time--has shown few results, despite 10 years of development at
costs of over $1.5 million. BLM envisioned the RDAWP program as a
means to provide industry and government with common tools to validate
production and to view production data in near real-time in an
automated and secure environment. BLM developed the concept of
remotely monitoring oil and gas production data through meetings held
with BLM field staff in 1999. Presently, many companies receive
production data in real-time via Supervisory Control and Data
Acquisition (SCADA) software. RDAWP works by BLM attaching specially
designed electronic equipment to the company's computer server, which
relays the SCADA production data to a BLM server. Currently, BLM has
only been able to access these electronic data through individual
voluntary agreements with companies--as BLM does not currently require
that operators of federal leases provide BLM access to raw production
data from the electronic flow computers. According to the BLM project
manager, if BLM staff had access to these data, BLM could potentially
complete production inspections more quickly and reduce the burden on
industry in fulfilling BLM audit requests for multiple years of
electronic flow computer production data and meter calibration
reports. Specifically, according to BLM's project manager and project
documents, RDAWP would provide BLM staff with a more automated means
to complete several gas production inspection activities, such as:
* Verifying Electronic Flow Computer Gas Calculations. First, RDAWP
would assist in verifying volumes reported by the operator on the
monthly production reports by integrating the reports into the RDAWP
software. Second, RDAWP would automatically independently recalculate
the gas volumes and compare it to the volume generated by the
electronic flow computer. Finally, RDAWP would reduce the need for BLM
staff to visit the field to complete this work as the data would be
available in the field office.
* Meter Calibration. Currently, meter calibration inspection
activities may be completed by either reviewing meter calibration
reports or actually witnessing a meter calibration. RDAWP would
greatly assist in this task because when electronic flow computers
were calibrated, it would generate an event log that would clearly
record and store the "as found" and "as left" calibration values. With
RDAWP, BLM staff would be able to determine from the office whether
meters had been calibrated within the required time frame, and if any
error was greater than 2 percent, which, according to BLM regulations,
requires that the operator correct and resubmit previous monthly
production reports.
* Other Inspection Activities. Finally, data obtained from the
electronic flow computers would also provide several other key data.
Currently, BLM requires gas sample analyses annually, unless otherwise
approved. As the BTU value of gas is necessary for calculating the
volume, according to a BLM official, the gas sample data must be
entered into the electronic flow computer. RDAWP's ability to pull in
data from the electronic flow computers would assist BLM staff in
ensuring that gas samples were being taken. Additionally, BLM would
more easily be able to track well status--or whether the well was
producing or not producing. BLM has historically faced challenges in
having accurate information on whether or not a well was producing.
RDAWP would allow BLM staff to see, on a daily basis, whether the well
was producing and how many days in a month it produced.
In 2003, BLM proposed a business case for obtaining real time
production data--which eventually became known as RDAWP--that
consisted of four phases:
Phase I. An initial pilot project encompassing 60 wells with one
operator in the Farmington, New Mexico, resource area.
Phase II. If BLM opted to proceed after Phase I, a second phase would
proceed with 300 to 600 wells, from three to four operators, and
include the Farmington, New Mexico; Durango, Colorado; and Buffalo,
Wyoming, field offices.
Phase III. The third phase would be full-scale use of RDAWP across all
federal leases.
Phase IV. The last proposed phase would be to apply the technology and
knowledge from RDAWP at the well head to other applications, such as
using it to monitor major pipelines and other elements of the nation's
infrastructure.
The 2003 BLM business case also states that there are no other
available alternatives to RDAWP that can deliver the requirements of
this proposal. Furthermore, while BLM acknowledged that oil and gas
companies may employ technologies similar to RDAWP for monitoring oil
and gas production, according to a BLM official, BLM lacks the
authority to access companies' secured servers to obtain this
production data. Finally, the contractor responsible for implementing
the RDAWP program proposed a roll-out schedule that would begin with
200 wells connected to RDAWP in the first quarter of 2004 and ending
in the third quarter of 2009 with a total of 108,500 wells connected.
As of the fourth quarter of 2009, BLM has completed trials in two
field offices, has an ongoing pilot project in one field office where
50 wells are connected to RDAWP, and spent in excess of $1.5 million
on the RDAWP program for fiscal years 2003 through 2009. Since 2003,
according to the current project manager, RDAWP pilot projects have
been conducted in two BLM field offices, Farmington, New Mexico, and
one in Wyoming--although the manager could not identify which Wyoming
field office. During these pilot projects, according to BLM officials,
improvements were made to the RDAWP technology. However, funding and
IT issues related to the Cobell lawsuit, according to a BLM official,
considerably slowed the project. Finally, when we asked BLM project
management staff to provide specific data on the $1.5 million RDAWP
expenditures, it was unable to do so.
In March 2009, we visited the Glenwood Springs, Colorado, BLM field
office to assess the effectiveness of the ongoing pilot project, which
had begun in late 2008. According to BLM staff, they had not yet used
the RDAWP system to assist in completing an actual production
inspection because the RDAWP software was incorrectly calculating
volumes. Additionally, RDAWP was unable to fully access the event logs
from the electronic flow computer or the operator-reported monthly
production report from BLM's inspection database. Finally, BLM staff
told us that they had not been given any criteria by which to evaluate
the RDAWP pilot project. BLM staff did say, however, that RDAWP could
be an effective tool if it worked as designed. We followed up with
staff in the Glenwood Springs, Colorado, field office in late July
2009 to learn whether or not any changes had occurred. A BLM official
told us that RDAWP now appeared to be calculating the volumes for the
50 wells correctly and that BLM management was working with the
company to increase the number of wells included in the RDAWP program
to those within the entire case. This would, according to the BLM
official, allow staff to use the software to help complete a single
production inspection.
Also, in early 2009, BLM updated its cost-benefit analysis plan for
RDAWP, which included elements of the contractor's roll-out schedule.
The roll-out schedule envisioned that by the end of the first quarter
in 2009, 200 wells would be connected to RDAWP, and that by the end of
the first quarter of 2010, approximately 9,000 wells would be
connected. This outcome appears unlikely given the limited number of
wells currently connected.
Despite the conclusion made by Interior in its 2003 business case
analysis, it appears that there are commercial alternatives to
Interior's efforts. During the development of RDAWP, another program
within BLM responsible for monitoring and auditing gas volumes
acquired commercially available off-the-shelf software to assist in
production verification. Specifically, in 2008 BLM's Helium program,
overseen by the Amarillo, Texas, field office, BLM worked with
producers and purchasers of helium to procure a common suite of
software. According to the BLM Helium program manager, the benefits of
this approach are that purchasers, transporters, and the seller (BLM)
have a common data platform through which they can verify volumes and
audit one another. According to the program manager, this software
cost approximately $500,000, which included training and 5 years of
support. As part of our review, we spoke with representatives of the
company that developed this software and found that it provides
similar functionality to that offered through RDAWP. Additionally,
according to a representative of the company participating with BLM in
the RDAWP program, this software is widely used within the oil and gas
industry, and has many of the functionalities outlined as goals for
the RDAWP program. In 2006, as part of BLM's RDAWP development
process, BLM completed an alternative analysis to examine its options
for its production verification program. This analysis compared three
options, including (1) maintaining the status quo and continuing to
rely on-the-ground inspections, (2) procuring a customized off-the-
shelf solution--RDAWP, or (3) developing software entirely in-house
for obtaining well head production data. However, it does not appear
as though BLM considered the software obtained by BLM's Helium program
in its analysis of option 2 because only the RDAWP option is included
in the section identifying customized off-the-shelf technology
alternatives. See appendix V for production verification tools and
policies used by other countries, states, and private companies, but
not widely used by Interior.
Interior's Efforts to Provide Inspection Staff with Mobile Computing
Capabilities For Use in the Field Are Moving Slowly and Are Years From
Full Implementation:
Interior's BLM and OEMM are independently developing the capacity for
inspection staff to (1) electronically document inspection results,
and (2) access reference documents, such as API standards and
measurement regulations, via laptops while in the field. BLM initiated
work on this tool in 2001, whereas OEMM is now in the preliminary
planning stages of a similar tool. According to agency officials,
widespread implementation of a mobile computing tool to assist with
production verification is still several years away.
In 2000, according to the BLM official previously responsible for
developing BLM's mobile computing capabilities, BLM identified a need
for an alternative to its current approach of documenting inspection
results on paper while in the field, and subsequently entering the
results in BLM's database when back in the office. At the time,
according to this official, BLM management identified two concerns
with the current approach; first, staff had to contend with duplicate
data entry--once in the field on paper, and once back in the field
office into the database; and second, inspection data were not being
entered into the database in a timely manner. In 2001, according to
this same official, BLM received funds to fulfill a requirement in the
Energy Policy and Conservation Act Amendments of 2000 for an inventory
of onshore oil and gas reserves and concluded that an investment in
mobile computing was warranted.[Footnote 58] The development of mobile
computing was initially directed toward work associated with drilling
inspections. At the time, according to this official, the Buffalo,
Wyoming, BLM field office was experiencing high drilling rates for
coalbed methane, and the field office manager was looking for ways to
minimize the amount of time petroleum engineer technicians spent in
the office entering data; the field office manager, according to a BLM
official, proposed that mobile computing could be part of the
solution. After evaluating several options, BLM selected one option
and started a pilot in 2001. According to feedback from petroleum
engineer technicians, the BLM official told us that initial results
were positive, with some technicians estimating a time savings of 50
percent through having the ability to document drilling inspection
data on a laptop, and later uploading those data into BLM's database.
The BLM project team then examined its applicability for other types
of inspections, including production. However, in 2003, Interior's IT
systems were seriously impacted by the Cobell Lawsuit.[Footnote 59]
The mobile computing project was initiated again in 2006 after BLM
received additional funding for seven field offices. BLM used
approximately $200,000 to purchase laptops designed to withstand use
in the field, for inspection staff in the seven offices. However,
despite this purchase of computers, BLM had not developed software for
electronically documenting production inspections. In April 2008, BLM
worked with a company specializing in field data collection software
development--including for the oil and gas industry--to explore
various mobile computing options for BLM. According to the BLM
official, over the course of several days, BLM and the company were
able to develop prototype electronic forms for the several types of
BLM oil and gas inspections through a slight modification of the
company's off-the-shelf software. More recently, in August 2009, a BLM
national inspection and enforcement coordinator told us that a BLM IT
advisory group decided to prioritize the electronic forms for
production inspections over other inspection types. However, the
official was unable to provide us with a time frame for when this
technology would be widely adopted at the field office level.
In our discussions with petroleum engineer technicians from the seven
field offices we visited, we learned that some staff in three of the
field offices we reviewed generally used laptops while in the field.
However, those staff using laptops stated that this use is not helping
reduce duplicate data entry because there are no electronic forms for
many of the inspections, and they currently lack the ability to
automatically upload their inspection results into BLM's inspection
database. Staff in all seven field offices told us that having the
capability to document inspections in the field and upload them into
the database at the end of the day would save time, allowing them to
spend more time in the field doing actual inspection work.
Additionally, the former project manager stated that the use of
electronic forms could also improve the reliability of inspection data
through the use of data edit checks. For example, an electronic form
could be designed so that duplicate inspection activities could not be
entered for the same inspection and that inspections could not be
closed out unless all the relevant data fields were populated.
According to OEMM officials, OEMM is also considering the use of
mobile computing in its inspection program. However, it is at the
conceptual stage and no money has yet been allocated to development.
The justification for moving toward mobile computing is the need for
OEMM inspectors to have access to large amounts of technical reference
material to complete inspections. For example, one official explained
that right now, some inspectors are carrying 50 pounds of paper with
them when they fly out to platforms to complete inspections, and that
the ability to access this reference material electronically would
benefit the inspectors. Moreover, with inspectors having the
capability to electronically document inspections in the field, OEMM
would be able to free up those data entry staff to work on other
programs, rather than their current practice of recording inspections
on paper and then handing the paper copies to other staff in the
district offices to enter into OEMM's inspection database. OEMM
officials also stated that electronic data entry would provide
additional controls for ensuring that the reliability of inspection
data remains high. For example, with the proper edit checks, OEMM
would not have had the data issues with the site security data entries
that prevented it from knowing the number of inspections it completed
between 2004 and 2007. Finally, OEMM officials stated that this
initiative would be funded under the program budget for updating
OEMM's entire database, called OCS (Outer Continental Shelf) Connect.
The officials told us that funding would not be available for at least
20 months, so full implementation of mobile computing is at least 2 to
4 years away.
Conclusions:
The Department of the Interior is charged with the critical role of
ensuring that the country's oil and gas assets are carefully developed
and that the American people receive fair compensation when these
assets are sold. A key part of this role consists of providing
reasonable assurance that oil and gas are accurately measured and that
measurement efforts undertaken by the private companies that are
developing these national resources are held to high standards.
Interior's current approach of delegating to BLM and OEMM the
responsibility for developing and updating oil and gas measurement
regulations, approving measurement technologies not addressed by
current regulations, and developing policies for commingling oil and
gas has resulted in inconsistent regulations and decisions regarding
measurement. This has resulted in inefficiencies and increased risk of
inaccurate oil and gas measurement. While Interior's Production
Coordination Committee, on which representatives of BLM, OEMM, and MMS
serve, has been tasked with providing advice on measurement issues,
the Committee's lack of formal decision-making authority for these
critical issues at the department level means that Interior cannot be
assured that it is accurately measuring federally produced oil and gas.
Additionally, because Interior has not determined the extent of its
authority over key elements of the oil and gas production
infrastructure, the result has been limited oversight of key
facilities, including pipelines and gas plants, which refine gas into
royalty-bearing saleable commodities. Furthermore, according to
Interior officials, in instances when pipeline companies own and
maintain meters on federal leases, Interior has limited direct access
to them or their associated production data. This absence of rigorous
federal oversight increases the risk that oil and gas may not be
accurately measured.
Interior also has not ensured that controls over where and how oil and
gas are measured are being consistently applied to leases located
offshore and onshore, and BLM does not provide sufficient criteria for
approving commingling agreements to enable staff to verify that oil
and gas are being measured and reported accurately under such
agreements. Without the ability to consistently track where and how
oil and gas are measured, Interior cannot be assured that production
reported to Interior is accurate.
Furthermore, Interior's delegation of production accountability
inspection programs to BLM and OEMM has resulted in inconsistent
emphasis on key areas affecting oil and gas measurement accuracy
across the two agencies. Also, while OEMM now appears to be able to
meet its annual goals for inspecting oil and gas producing leases
under its revised strategy, BLM has not consistently been able to do
so. This lack of consistency, as well as BLM's inability to inspect
all wells, does not provide Interior sufficient assurance that it is
properly measuring and accounting for oil and gas removed from federal
lands.
Moreover, BLM faces challenges overseeing production verification
through its field office structure. While decentralized management
approaches can be effective, BLM's structure and lack of top level
review has led to inconsistencies within its production verification
program across field offices. Without such review, BLM is not
employing internal control activities specified in federal standards.
Further, BLM's database and hard copy files have a wealth of
information on oil and gas production inspections, but without
adequate controls to ensure complete and accurate production
inspections and lacking the transfer of this information into
Interior's electronic data systems, BLM may lack adequate data to
track annual progress toward meeting its goals and demonstrating
compliance with its regulations.
In addition, according to agency staff, because Interior has not
provided sufficient or timely training for many of its key staff
responsible for oil and gas measurement, knowledge gaps exist
departmentwide, but are particularly pressing in some disciplines and
in some BLM field offices. Compounding this, according to agency
staff, program operations at many BLM locations are being further
impeded by high staff turnover rates. Furthermore, while the recent
downturn in the oil and gas sector has reduced competition between
Interior and the private sector for staff, as the economy improves and
oil and gas companies begin hiring again, Interior may, once again,
increasingly be challenged in attracting and retaining qualified
staff. Until Interior can maintain a well-trained and stable
production verification workforce, Interior risks not having staff
with sufficient knowledge to identify inaccurate oil and gas
measurement.
Finally, Interior has begun developing tools it anticipates will lead
to greater staff productivity, but it has been unable to deploy these
tools on a widespread basis. Specifically, while BLM has made progress
in developing in-house software for obtaining and analyzing gas
production data from electronic flow computers, it has fallen behind
the private sector in collecting and analyzing these data and adopting
common software that facilitates data exchanges for verifying oil and
gas volumes. Additionally, while BLM has recognized the need for staff
to have mobile computing technology for documenting production
inspections in the field, it has not developed the necessary
technology. OEMM has recently expressed an interest in developing a
similar tool for its inspectors, yet no coordination has occurred
between BLM and OEMM on the development of such a tool.
Recommendations for Executive Action:
To increase Interior's assurance that it is accurately measuring oil
and gas produced on federal lands and waters, we are making 19
recommendations to the Secretary of the Interior.
To improve the consistency and efficiency of Interior's oil and gas
measurement regulations and policies, we recommend that the Secretary
empower a centralized panel consisting of staff with measurement
expertise from BLM and OEMM to take the following actions:
* increase consistency between offshore and onshore measurement
regulations, as appropriate;
* annually review changes in the industry measurement technologies and
standards that Interior's regulations reference to determine whether
the related regulations should be updated;
* provide departmentwide guidance on measurement technologies not
addressed in current regulations and approve variances for measurement
technologies in instances when such technologies are not addressed in
current regulations or departmentwide guidance; and:
* develop guidance clarifying when federal oil and gas may be
commingled and establish standardized measurement methods in such a
way that production can be adequately measured and verified.
To provide greater assurance that key elements in the oil and gas
production infrastructure are adequately overseen, the Secretary
should determine the extent to which Interior has authority regarding:
* pipelines, including meters that pipeline companies own, as well as
other methods transportation companies use to ship and measure oil and
gas produced from federal leases; and:
* gas plants that process gas from federal leases, including the
requirements and responsibilities for approving gas plant meters, and
conducting inspections of them.
If Interior determines that its authority over any of these components
is lacking or unclear, the Secretary should seek the appropriate
authority or clarification from Congress.
To help ensure that Interior is consistently tracking where and how
oil and gas are measured, the Secretary should require that:
* BLM track all onshore meters, including information about meter
location, identification number, and owner;
* MMS require onshore operators to report meter identification numbers
in the required monthly production reports; and:
* BLM petroleum engineers work with BLM staff conducting production
verification to confirm that commingling agreements are (1) consistent
with Interior guidance on such agreements, and (2) are adequately
structured to facilitate key production verification activities before
such agreements are approved.
To help ensure that Interior's production accountability inspection
program consistently addresses key areas affecting measurement
accuracy and that BLM meets its inspection goals, the Secretary should:
* establish goals for (1) witnessing onshore oil and gas meter
calibrations, (2) witnessing onshore and offshore gas sample
collections, (3) comparing onshore reported BTU values with gas
analyses, and (4) inspecting onshore and offshore orifice plates and
meter tubes; and:
* consider an alternative onshore production inspection strategy that
enables BLM to inspect all wells within a reasonable time frame, given
available resources.
To improve the consistency of Interior's management of its onshore
production and inspection program, the Secretary should direct BLM to:
* review and revise, as appropriate, its oversight of field and state
offices and train managers involved in BLM's inspection and
enforcement program to ensure adequate and appropriate review of
personnel, processes, and production, consistent with standards for
internal controls; and:
* conduct reviews of the quality and completeness of the hard copy
production inspection program files across field offices periodically
and ensure that the data in these files are accurately entered into
its database.
To address gaps in critical oil and gas measurement abilities, the
Secretary should:
* direct BLM and OEMM to ensure that key onshore and offshore
production verification staff have received initial standardized
training necessary to effectively carry out their job functions and
receive ongoing measurement training as needed; and:
* determine what additional policies or incentives are necessary, if
any, to attract and retain qualified measurement staff at sufficient
levels to ensure an effective production verification program.
To improve the tools available to Interior's production inspection
staff, the Secretary should:
* direct BLM to evaluate its commitment to further develop its in-
house software, in light of the functionality, cost, and ease of
adoption by Interior and industry of commercially available software;
and present the results of this evaluation to Congress;
* require all companies purchasing federal leases to immediately
provide Interior access to oil and gas production data generated by
electronic flow computers to leave open a range of future options for
electronic data exchanges with operators;
* direct BLM to implement a mobile computing solution for its
inspection and enforcement program to allow staff to spend more time
in the field conducting inspections and to improve the reliability of
the inspection data; and:
* coordinate onshore and offshore inspection staffs' efforts to design
and implement a mobile computing solution for inspectors in the field,
while taking into account any unique or specific needs associated with
onshore versus offshore inspections.
Agency Comments and Our Evaluation:
We provided a draft of this report to Interior for review and comment.
Interior generally agreed with our findings and fully concurred with
16 of our 19 recommendations and partially concurred with the
remaining three recommendations.
With regard to the recommendation in our draft report which stated
that the Secretary empower the Interior's Production Coordination
Committee to: (1) increase consistency between offshore and onshore
measurement regulations, as appropriate; (2) review changes in the
industry measurement technologies and standards annually that
Interior's regulations reference to determine whether the related
regulations should be updated; (3) assess measurement technologies not
addressed in current regulations and approve variances, as
appropriate; and (4) develop guidance clarifying when federal oil and
gas may be commingled and establish standardized measurement methods
in such a way that production can be adequately measured and verified,
Interior agreed with our findings and the need for more consistency in
these decisions. However, Interior expressed uncertainty as to whether
the Production Coordination Committee (PCC) is the appropriate entity
to oversee the implementation of the recommendations because it was
formed as an ad hoc body. While Interior acknowledged that the PCC
might be the appropriate body, it believed that the Secretary should
be allowed to make such a determination. We appreciate Interior's
acknowledgement that the current system, where these authorities are
dispersed, results in inconsistencies and that some centralization of
authority is needed. In light of these concerns, we agree that some
flexibility on determining whether the PCC, or some other body, should
be empowered with this departmentwide authority is justified.
Accordingly, we modified our recommendation to allow for the Secretary
to empower a centralized body comprised of staff from OEMM and BLM to
carry out the roles we described.
Interior partially concurred with our recommendation that a
centralized panel should assess measurement technologies not addressed
in current regulations and approve variances, as appropriate. Interior
agreed that it should periodically assess measurement technologies not
addressed by regulations, and provide staff with guidance when
technologies are not addressed by its regulations. Interior noted they
are considering a range of alternatives to provide additional controls
for providing assurances that variance approvals are subject to
additional review. We are concerned that continued reliance on
dispersed authority for variances may not fully address the
longstanding challenges with ensuring consistency across
jurisdictional boundaries, and that without a strong framework to
ensure greater centralization and coordination, such inconsistencies
may persist. We strongly believe that a centralized panel that has
shared expertise from both OEMM and BLM would be best suited to
address new, and increasingly complicated, measurement technologies.
It is our hope that by empanelling departmentwide expertise with the
authority to regularly update regulations, fewer variances would be
needed. We further believe that this same panel could issue
departmentwide guidance on the uses of new technologies not already
addressed by regulations, thereby limiting the need for any
distributed decision making and the related inconsistencies we found
during the course of our work. Because we are concerned that companies
may request to use advanced technologies not well understood, and
because of the limited background measurement knowledge of some
Interior staff who approve variances, we believe it is important that
the most knowledgeable people in the department make reasoned
decisions on their approvals. In deference to Interior's concerns, we
modified our recommendation to allow for the centralized panel to
develop departmentwide guidance on the use of technologies that it
determines to be technically sufficient but not covered by current
regulations, and that the centralized panel approve variances only in
cases where such technologies are not addressed by either current
regulations or departmentwide guidance.
Finally, Interior partially concurred with two of our recommendations
addressing IT issues. While Interior agreed with our recommendation
that BLM conduct a study of its RDAWP program in light of commercially
available software, it did not agree that the results of the study be
presented to Congress. Rather, Interior preferred that the results be
presented only to the Secretary. We believe that Interior could
provide the results of a study to the Secretary as an interim measure,
but given this technology's potential to significantly improve
Interior's production verification efforts, Congress should have clear
and thorough information available to it when determining how federal
funds are spent. As such, we made no change. Interior also partially
agreed with our recommendation that Interior should coordinate its
onshore and offshore inspection staffs' efforts to implement a mobile
computing solution for inspections in the field. Interior expressed
concerns that the different operating environments may necessitate
different technological solutions for BLM and OEMM staff. We fully
recognize this issue, and understand that the work environments
offshore and onshore may lead the agencies to develop different
solutions. However, we believe that BLM's staff have accumulated a
large body of knowledge on this issue after its 10-year effort at
developing a system, and that this knowledge may help OEMM as it works
toward developing its own mobile computing solution. Accordingly, we
modified our recommendation to clearly state the BLM and OEMM should
coordinate the development of a mobile computing solution for their
staffs, taking into account any unique or specific needs associated
with onshore versus offshore inspections. This allows each agency the
flexibility to adopt an approach that best meets the agencies' needs,
while ensuring that both agencies keep one another informed of their
progress thereby reducing the possibility of duplicative or
unnecessary work, and providing the opportunity to take advantage of
any economies of scale that could exist. Interior also provided
several technical clarifications, which we incorporated as
appropriate. Appendix II contains the Department of the Interior's
comment letter.
As agreed with your offices, unless you publicly announce the contents
of this report earlier, we plan no further distribution until 30 days
from the report date. At that time, we will send copies of this report
to the appropriate congressional committees, the Secretary of the
Interior, the Director of the Bureau of Land Management, the Director
of the Minerals Management Service, and other interested parties. In
addition, this report will be available at no charge on the GAO Web
site at [hyperlink, http://www.gao.gov].
If you or your staff members have any questions about this report,
please contact me at (202) 512-3841 or ruscof@gao.gov. Contact points
for our Offices of Congressional Relations and Public Affairs may be
found on the last page of this report. GAO staff who made major
contributions to this report are listed in appendix VII.
Signed by:
Frank Rusco:
Director, Natural Resources and Environment:
List of Requesters:
The Honorable Jeff Bingaman:
Chairman:
Committee on Energy and Natural Resources:
United States Senate:
The Honorable Nick J. Rahall, II:
Chairman:
Committee on Natural Resources:
House of Representatives:
The Honorable Darrell Issa:
Ranking Member:
Committee on Oversight and Government Reform:
House of Representatives:
The Honorable Carolyn Maloney:
House of Representatives:
[End of section]
Appendix I: Scope and Methodology:
This report assesses (1) the extent to which the Department of the
Interior's (Interior) production verification regulations and policies
provide reasonable assurance that oil and gas are accurately measured;
(2) the extent to which Interior's offshore and onshore production
accountability inspection programs consistently set and meet program
goals and address key factors affecting measurement accuracy; and (3)
Interior's management of its production verification programs.
For all three report objectives, we reviewed relevant laws,
regulations, and Interior, Bureau of Land Management (BLM), and
Offshore Energy and Minerals Management (OEMM) guidance. We
interviewed officials in BLM headquarters and officials from ten BLM
field offices (and their associated state offices), selected using
nonprobability samples, that provided a range of oil and gas
operations and jurisdictions.[Footnote 60] Specifically, we visited
and interviewed officials in three BLM state offices (Colorado, New
Mexico, and Wyoming) and eight BLM field offices (Glenwood Springs and
White River in Colorado; Vernal in Utah; Buffalo, Pinedale, and
Rawlins[Footnote 61] in Wyoming; and Carlsbad[Footnote 62] and
Farmington in New Mexico) and interviewed by telephone officials in
two additional state offices (Montana and Utah).
Additionally, we interviewed officials in four OEMM district offices
(and their associated regional offices) that provided a range of
geographic areas and jurisdictions. Specifically, we visited and
interviewed officials in one OEMM regional office (Gulf of Mexico) and
one OEMM district office (Lafayette, Louisiana) and interviewed by
telephone officials in one additional OEMM regional office (Pacific)
and four additional OEMM district offices (Lake Charles, Lake Jackson,
New Orleans, and California). In addition, we interviewed
representatives from 10 state oil and gas agencies, 8 oil and gas
companies, and 6 regulatory entities overseeing oil and gas
measurement from other countries about key areas that affect oil and
gas measurement accuracy and their production verification programs.
In addition, we collected and analyzed data from both BLM's Automated
Fluid Minerals Support System (AFMSS) and OEMM's Technical Information
Management System (TIMS).
To assess the extent to which Interior's production verification
regulations and policies provide reasonable assurance that oil and gas
are accurately measured, we analyzed BLM's and OEMM's laws and
regulations addressing oil and gas measurement and conducted
semistructured interviews with key BLM and OEMM production
verification staff, including BLM petroleum engineers; BLM petroleum
engineer technicians; BLM production accountability technicians; OEMM
petroleum engineers; and OEMM inspectors. We also compared several
aspects of BLM's and OEMM's oil and gas measurement regulations to
identify areas of variation. We further interviewed OEMM regulatory
affairs staff and BLM headquarters staff about the processes employed
by both OEMM and BLM for updating their measurement regulations.
Additionally, we examined the laws and regulations for providing the
Secretary of the Interior authority to oversee key areas of oil and
gas infrastructure, including gas plants, meters, and pipelines; we
also interviewed Interior officials within its Solicitor's Office to
obtain their legal assessment of Interior's authority over these
areas. Finally, we examined BLM and OEMM regulations for how oil and
gas measurement points are tracked and what criteria the agencies use
to approve requests to commingle oil or gas production prior to
measurement. To learn more about tracking measurement points and how
commingling affects measurement accuracy, our semistructured interview
guide included questions addressing these topics. During these
discussions, we used a standard interview protocol, in which
respondents were asked a standard set of open-ended questions. We
asked these BLM and OEMM staff to address whether they could identify
official measurement points and what effect commingling agreements had
on their ability to accurately verify production.
To assess the extent to which Interior's offshore and onshore
production accountability inspection programs consistently set and
meet program goals and address key factors affecting measurement
accuracy, we reviewed and analyzed BLM's and OEMM's inspection program
goals and inspection data and assessed to what extent these programs
addressed key areas affecting measurement accuracy. To assess the
extent to which Interior's production accountability inspection
program consistently sets program goals, we obtained and reviewed
OEMM's and BLM's inspection strategies and identified areas of
variation. To assess the extent to which OEMM and BLM were meeting the
program goals for completing inspections, we requested and analyzed
production inspection data from both BLM and OEMM. Specifically, we
collected and analyzed data from BLM's AFMSS to determine the extent
to which BLM was meeting its statutory and agency goals for completing
production inspections. Prior GAO work concluded that, because of the
Cobell litigation which resulted in IT systems shutting down for
extended periods of time, several BLM field offices were unable to
accurately identify high priority cases--cases requiring annual
inspections--because they could not readily access the Minerals
Management Service's (MMS) monthly production reports to examine
volumes. Accordingly, we limited our analysis to determining whether
BLM was meeting its inspection goal for low priority cases--cases
requiring inspections once every 3 years. We collected and analyzed
production inspection data for fiscal years 1998 through 2009 to
determine the frequency with which BLM was inspecting active cases. We
further collected and analyzed BLM's AFMSS data on measurement
activities, including meter calibrations and tank gaugings, completed
during production inspections for fiscal years 2004 and 2008. We
assessed the reliability of BLM's AFMSS production inspection data by
(1) performing electronic testing for obvious errors in accuracy and
completeness; (2) reviewing existing documentation about the data and
the system that produced them; (3) interviewing agency officials
knowledgeable about the data; and (4) verifying with agency officials
a limited sample of our results. We determined that BLM's data
documenting completed production inspections were sufficiently
reliable for the purposes of this report. However, based on our
findings related to production inspection activities and our limited
file review, we had less confidence in those data. However, we
determined that the meter calibration and tank gauging measurement
code data were sufficiently reliable to indicate trends over time, but
not the actual number of activities completed.
Additionally, we collected and analyzed data from OEMM's TIMS database
to determine the extent to which OEMM was meeting its statutory and
agency goals for witnessing meter calibrations and conducting site
security inspections for fiscal years 2004 through 2008. We assessed
the reliability of OEMM's TIMS production inspection data by (1)
performing electronic testing for obvious errors in accuracy and
completeness; (2) reviewing existing documentation about the data and
the system that produced them; and (3) interviewing agency officials
knowledgeable about the data. We determined that, based on our
discussions with OEMM officials, only the fiscal year 2008 data was
sufficiently reliable for our reporting purposes.
Finally, to identify key areas that affect measurement accuracy not
currently addressed by Interior's production accountability programs,
we reviewed technical papers and interviewed representatives from
industry, independent research organizations, the U.S. National
Institute of Standards and Technology, the American Petroleum
Institute, and BLM and OEMM officials responsible for oil and gas
measurement. For these interviews, we used a standardized interview
protocol, in which respondents were asked a standard set of open-ended
questions. We asked these respondents to identify key factors that
affect measurement accuracy. We then analyzed the extent to which
BLM's and OEMM's production inspection program addressed the key areas
affecting measurement uncertainty.
To evaluate Interior's management of its production verification
programs, we examined its oversight activities, human capital
policies, and the extent to which Interior was successful in
developing key tools to assist its production inspection staff. To
examine Interior's oversight of its oil and gas production
verification program, we reviewed documentation on both BLM's and
OEMM's internal reviews of their production verification programs,
including the criteria for assigning a risk rating to the programs. We
also interviewed agency officials about BLM's and OEMM's organizations
as they relate to key oil and gas production verification staff,
including the supervisory relationships. To examine internal controls
related to production inspection documentation, we selected a
nongeneralizable sample of hard copy BLM files from four of the seven
field offices we visited. We nonrandomly selected files from fiscal
years 2004 through 2008 to provide us with a range of measurement
activities, including meter calibrations, tank gaugings, meter
provings, and run ticket verifications. Specifically, we reviewed 7
files in the Vernal, Utah, field office; 9 files in the White River,
Colorado, field office; 9 files in the Pinedale, Wyoming, field
office; and 18 files in the Buffalo, Wyoming, field office. We
reviewed the files for completeness and whether the files supported
data recorded in BLM's database. In total, we reviewed 43 files out of
a possible 3,566 available files to select from between fiscal years
2004 and 2008 for the four field offices we reviewed. Because we did
not conduct a truly random sample, our analysis does not indicate the
prevalence or extent of the problems we identified. This applies to
both the field offices whose files we reviewed, as well as the 28
field offices whose files we did not review. We selected hard copy
files based on OEMM data that indicated that the files included site
security inspections and indications the files might contain
additional information that would inform our understanding of OEMM's
overall inspection process. Our nongeneralizable sample included a
review of 20 out of a total of 562 available hard copy inspection
files for fiscal years 2007-2008 in those two district offices.
Because we did not conduct a truly random sample, our analysis does
not indicate the prevalence or extent of the problems we identified.
This applies to both the district offices whose files we reviewed, as
well as the five district offices whose files we did not review. We
also collected and analyzed BLM AFMSS production inspection data from
the nine field offices we reviewed for fiscal years 2004 through 2008
and used BLM's documentation criteria to assess whether data was
correctly coded. We also examined MMS and BLM staffing and training
data. Specifically, we collected and analyzed staffing data for the
nine BLM field offices, four OEMM district offices and two OEMM
regional offices we reviewed, for fiscal years 2004 through 2009, to
calculate turnover rates for BLM petroleum engineers, BLM petroleum
engineer technicians, BLM production accountability technicians, OEMM
petroleum engineers, and OEMM inspectors. We obtained human capital
data from Interior's Federal Personnel and Payroll System (FPPS) for
all nine BLM field offices and for four OEMM district offices. For
regional OEMM staff performing the work of petroleum engineers, we
obtained human capital data from regional office officials. We
assessed the reliability of the FPPS data for BLM and OEMM staff by
(1) interviewing agency officials knowledgeable about the data, (2)
working closely with agency officials to identify any data problems,
and (3) corroborating, on a limited basis, staff names included in the
FPPS with names of staff on sign-in sheets obtained during our site
visits and interviews.
Additionally, we reviewed training records and interviewed BLM and
OEMM staff about training requirements and course offerings. In
reviewing BLM's Remote Data Acquisition for Well Production program,
we collected and analyzed project timelines, budget information, and
planning documents. We also interviewed BLM project managers;
representatives from the oil and gas company voluntarily participating
in the pilot project; and BLM staff in the Glenwood Springs, Colorado,
field office who had access to the software about the programs'
effectiveness. To learn about oil and gas production monitoring and
verification software used in the private sector, we interviewed oil
and gas company representatives about their software, as well as held
meetings with oil and gas software manufacturers. To assess BLM's and
OEMM's efforts to develop a mobile computing option for field
inspection staff, we analyzed project documentation, interviewed
project managers, and discussed the potential applications of mobile
computing with BLM staff from nine field offices and OEMM staff from
four district offices.
Finally, in order to develop an informed view of how others involved
in oil and gas production seek to perform similar functions, we
examined how states, other countries, and private companies perform
such functions. In particular, we reviewed state government
regulations and policies and interviewed regulatory officials from a
nongeneralizable sample of 10 states selected to represent states with
the most production in barrels of oil equivalent. These states
included Alaska, California, Colorado, Kansas, Louisiana, New Mexico,
Oklahoma, Texas, Utah, and Wyoming. Further, we interviewed
representatives from eight oil and gas producers, representing a range
of scales of operations. We also reviewed the oil and gas regulations
of Canada's Alberta, British Columbia, Newfoundland, and Labrador
provinces; Mexico; Norway; and the United Kingdom; and interviewed
their regulatory officials. We selected these countries on the basis
of several criteria, including the volume of national production. We
were unsuccessful in our attempts to also obtain information and
interview officials with relevant expertise from Russia and Kuwait.
We conducted this performance audit between October 2008 and March
2010 in accordance with generally accepted government auditing
standards. Those standards require that we plan and perform the audit
to obtain sufficient, appropriate evidence to provide a reasonable
basis for our findings and conclusions based on our audit objectives.
We believe that the evidence obtained provides a reasonable basis for
our findings and conclusions based on our audit objectives.
[End of section]
Appendix II: Comments from the Department of the Interior:
United States Department of the Interior:
Office Of The Secretary:
Washington, D.C. 20240:
February 26, 2010:
Mr. Frank Rusco:
Director, Natural Resources and Environment:
Government Accountability Office:
441 G Street, N.W.
Washington, D.C. 20548-001:
Dear Mr. Rusco:
Thank you fur the opportunity to review and comment on the Government
Accountability Office's (GAO) draft report entitled, "Oil, And Gas
Management: Interior's Oil and Gas Production Verification Elfarts Do
Not Provide Reasonable Assurance of Accurate Measurement of-Production
Volumes," (GA0-00-000). The Department of the Interior (Department)
appreciates the recognition of its efforts currently underway to
implement the GAO's recommendations. The Department generally agrees
with the findings and fully concurs with sixteen of the
recommendations.
As mentioned in technical comments submitted earlier, four
recommendations that Interior's Production Coordination Committee take
actions to address GAO findings should be directed to the Secretary to
delegate for resolution as appropriate. The Production Coordination
Committee is an ad-hoc committee established to oversee cross-bureau
coordination and collaboration and may be the appropriate group to
address these recommendations. However, the Secretary should make that
determination.
The Department partially agrees with the recommendation to "assess
measurement technologies not addressed in current regulations and
approve variances, as appropriate." The Department agrees that
measurement technologies should be periodically assessed and agency
guidance provided; however, we do not agree that individual onshore
variances in the use of measurement technology should be approved by
the PCC or any other headquarters office. These offices are too
removed from the variance request to make timely and informed
decisions. The 13LM is currently exploring ways to ensure that the
approval of variances is properly reviewed and if effective,
ultimately incorporated into national guidance. Establishing variance
review teams who can quickly review variance requests, or requiring
additional review by second-level professionals prior to management
approval are two of several possible alternatives to resolve the
issues identified by the GAO.
The Department would also prefer that GAO's recommendation for the
Secretary "to direct BLM to evaluate its commitment to further
developing its in-house software, in light of the functionality, cost
and ease of adoption by Interior and industry of commercially
available software, and present the results of this evaluation to
Congress;" he revised to allow presentation of such an evaluation and
agency recommendations to the Secretary for further consideration.
The Department partially concurs with the final recommendation, which
is to coordinate onshore and offshore inspection staffs efforts to
design and implement a mobile computing solution for inspections in
the field. The Bureau of Land Management (BLM) and the Minerals
Management Service (MMS) will continue to assess technology and
research the use of a mobile computing solution for their inspectors.
There are technical constraints such as intrinsic safety, weight, and
space, which must be considered for offshore implementation and may
require different solutions.
As noted in the draft report, oil and gas leasing and development
onshore, managed by the BLM, and offshore, managed by the MMS, operate
in different regulatory and operational environments. The Department
is focused on standardizing common agency practices, where
appropriate, particularly those that make operations more efficient
and effective. Both the BLM and the MMS arc working to develop new
regulatory requirements regarding commingling of produced oil and gas
from different sources that would be appropriate in their respective
environments.
The BLM and the MMS are collaborating on many important issues, such
as the revision of Onshore Order f13, which will require onshore
operators to include meter identification numbers on monthly
production reports. Also, the BLM and the MMS are reviewing the
Department's authority to regulate gas plants that process gas from
Federal leases, including the requirements and responsibilities for
approving gas plant meters and conducting inspections of them. This
will lead to appropriate inspection and enforcement measures by both
bureaus.
Technical comments on the draft report have been provided separately.
If you have any questions about this response or the technical
comments, please contact LaVanna Stevenson-Harris, BLM Audit Liaison
Officer. at 202-912-7077, or Andrea Nygren, MMS Audit Liaison Officer.
at 202-208-4343.
Sincerely,
Signed by:
Wilma A. Lewis:
Assistant Secretary:
Land and Minerals Management:
[End of section]
Appendix III: Four Examples of the Bureau of Land Management's (BLM)
Inconsistent Meter Approvals:
Variances to BLM's measurement regulations are made by the authorized
officer at the field office level without additional review. As a
result of this, there have been instances of inconsistent approvals at
both the field office and state office level. Specifically, we found
four instances of measurement technologies that had been approved in a
possibly inconsistent manner: (1) electronic flow computers, (2) Wafer
V-Cone meters, (3) truck-mounted Coriolis meters, and (4) flow
conditioners.
Electronic Flow Computers. BLM's initial approvals of electronic flow
computers were inconsistent across its field offices, and subsequent
state policies authorizing their use were issued independently between
2004 and 2009. According to a BLM official, beginning in the early
1990s, oil and gas companies began using electronic flow computers--
which are not addressed in BLM's 1989 gas measurement regulations--in
lieu of chart recorders for measuring and recording gas volumes. BLM
regulations require the authorized officer at the field office to
ensure that any alternative method of measurement be approved only if
it was equal to or better than what the regulations addressed. This
official told us that electronic flow computers were approved with
both inconsistent conditions of approvals, or had no approvals at all.
Partly in response to this new technology, BLM wrote and published
draft gas measurement regulations in the January 1994 Federal Register
for public comment. These draft regulations, according to a BLM
official, would have resolved internal inconsistencies with approving
electronic flow computers by establishing criteria for granting
approvals. BLM never finalized its revised gas measurement
regulations. Rather, 10 years later, individual BLM state offices--
beginning in 2004 with Wyoming and ending in July 2009 with Alaska--
separately issued standardized Notices to Lessees establishing
standards for the use of electronic flow computers. At least one
standard included in these policies was initially included 14 years
earlier in the draft 1994 gas measurement regulations.
Wafer V-Cone Meters. BLM has inconsistently approved Wafer V-Cone
meters at the field office level. In the mid 1990s, a manufacturer
developed a meter designed to provide accurate gas measurement with
significantly shorter lengths of upstream and downstream meter tubes,
as well as accurately measure gas associated with liquids. The meter--
called a Wafer V-Cone meter--is similar to an orifice meter in that it
measures the differential pressure, along with other parameters used
in calculating the volumes. The Wafer V-Cone was marketed in areas
with coal-bed methane production, as coal-bed methane is frequently
produced with large quantities of water. According to BLM documents,
prior to 2006, BLM field offices had received and approved requests
for installing Wafer V-Cone meters on federal leases. However, BLM
found that the conditions of approvals and the policies for approving
them were inconsistent between field offices. Later, BLM found that
Wafer V-Cone meters did not meet the manufacturer's stated
specifications for accuracy. In 2005, under the direction of BLM, the
manufacturer contracted with an independent flow measurement lab to
study the conditions under which Wafer V-Cone meters could accurately
measure gas. The research showed that the Wafer V-Cone manufacturer's
stated ranges for operating the meter were not accurate and that,
while Wafer V-Cones could accurately measure gas, it could only do so
within a narrow operating range. According to a BLM official, Wafer V-
Cone meters tend to undermeasure gas when high volumes are flowing
through it and over-measure gas when low volumes are flowing through
it. In November 2006, BLM issued a memo clarifying the flow conditions
under which the authorized officer in the field offices could approve
the Wafer V-Cone. The memo also stated that all previously approved or
unapproved Wafer V-Cone meters would have to be brought into
compliance within a "reasonable time frame." During the course of our
work, we obtained one field office's plan for bringing Wafer V-Cones
presently measuring federal gas into compliance, which was dated
January 20, 2009--2 years after the initial BLM policy was put into
place--which requested that operators bring their Wafer V-Cone meters
into compliance by May 1, 2009. In this intervening time, according to
a BLM official, federal gas was inaccurately measured. Some operators
at the time of our visit in May 2009 had already begun retro-fitting
the meter runs or replacing Wafer V-Cones with the more traditional
orifice meters to bring the measurement into compliance. A BLM
official estimated that the total number of meter reconfigurations
will be in the thousands, with per-well costs ranging between $500 and
$1,200. Finally, according to a BLM official, a second round of
testing on Wafer V-Cones has recently been completed and BLM is
assessing whether any revisions to its current approval conditions for
the meters are warranted.
Truck-Mounted Coriolis Meters. Because BLM does not centrally approve,
review, or track approved variances to measurement regulations, it was
unaware if truck-mounted Coriolis meters had been inconsistently
approved. In December 2008, BLM headquarters issued a memo stating
that it knew of at least one field office that was allowing a truck-
mounted Coriolis meter to measure federal oil for sales. Since
Coriolis meters are not positive displacement meters, which are the
only meters currently addressed by BLM's oil measurement regulations,
they must receive a variance from the local authorized officer if used
in that jurisdiction. The BLM memo requested that, in order to
identify the extent of the use of truck-mounted meters for oil
measurement, all field offices provide BLM headquarters data on the
make of the meter, the number of facilities from which oil is loaded,
the accuracy of specifications, the cost, and the field offices'
staffs' impression of its performance versus that of manual tank
gauging.
Flow Conditioners. BLM's absence of a formal policy addressing flow
conditioners is leading to inconsistent field office decisions on the
use of flow conditioners. Flow conditioners--devices placed within the
upstream portion of the meter run to both stabilize the gas flow and
allow for a shorter meter run--are not addressed by current gas
measurement regulations. Accordingly, a variance from the authorized
officer is necessary prior to installing flow conditioners in the
field. However, according to BLM officials from all seven field
offices we visited, operators have installed them without approved
variances. According to one BLM petroleum engineer, operators may have
begun using them believing that because BLM allowed a similar
technology--straightening vanes--that BLM would also allow flow
conditioners. However, BLM field offices are now taking an
inconsistent approach for retroactively approving them. For example,
an official in one field office told us that the office's engineers
were planning to hold a meeting to discuss a strategy for addressing
flow conditioners, whereas an official in another field office told us
that management was not encouraging staff to examine the issue.
Furthermore, while an official from one BLM field office told us that
when petroleum engineer technicians identify unauthorized use of flow
conditioners in the field, they will issue an incident of
noncompliance, while an official in another field office told us that
they do not--reasoning that the problem is because of BLM's out-of-
date measurement policies, not the operators' use of flow
conditioners. To date, BLM does not have a national policy on flow
conditioners and has not completed any independent testing on flow
conditioners' effects on measurement, though one BLM official has been
reviewing data from studies.
[End of section]
Appendix IV: Analysis of the Department of the Interior's (Interior)
Hiring, Training, and Retaining of Critical Measurement Staff:
Interior has had challenges in hiring, training, and retaining staff
for many of its critical measurement positions. The following section
provides additional detail on the Bureau of Land Management's (BLM)
petroleum engineers, BLM petroleum engineer technicians, BLM
production accountability technicians, Offshore Energy and Minerals
Management's (OEMM) petroleum engineers, and OEMM inspectors.
BLM Petroleum Engineers. BLM has struggled to hire qualified staff to
fill the petroleum engineer positions in its field offices and to
provide those it does hire with adequate training to improve their
knowledge, skills, and abilities; moreover, BLM continues to
experience high turnover in these positions. According to BLM data
obtained from BLM's Human Capital office, for the seven field offices
we reviewed, approximately 60 percent of the staff in the petroleum
engineer position had a degree in petroleum engineering. Others
currently serving as petroleum engineers held degrees in other areas,
including chemical engineering, mechanical engineering, and civil
engineering. Additionally, one petroleum engineer told us that oil and
gas measurement is not typically covered in courses in engineering
school and, thus, engineers did not necessarily have detailed
backgrounds in oil and gas measurement or production verification
activities. According to some BLM petroleum engineers, hiring
qualified staff can be challenging, as both BLM and oil and gas
companies are hiring from the same pool of applicants, but oil and gas
companies are able to offer their engineers much higher compensation
than BLM.
BLM has not provided consistent and formal training for recently hired
petroleum engineers, nor is there a requirement for any continuing
education. According to a BLM training coordinator, BLM has offered
training to petroleum engineers once since 1999. In 2007, BLM held a 5-
day course that focused on how to process drilling permits and review
commingling agreements, among other topics. During that course, the
training coordinator noted, it was clear that some petroleum engineers
required remedial training in some areas and course instructors
arranged for several tutorials to be held in the evening to review
selected engineering concepts. The training coordinator further stated
that there is a definite need for more petroleum engineer training,
but no funding had been available for such training in recent years.
According to the training coordinator, the lack of consistent formal
training for petroleum engineers could have significant impacts on the
decisions these petroleum engineers make, limit their ability to
perform certain functions, and limit their understanding of how their
decisions can affect overall production accountability within BLM.
Regarding concerns over decision making, some current petroleum
engineers noted that they had serious concerns about how prior
petroleum engineers had made decisions. According to one petroleum
engineer, because of some past decisions on commingling and allocation
agreements, it was unlikely production verification staff could
correctly verify the allocation of volumes, raising uncertainty as to
whether federal oil and gas were being properly measured and reported.
Furthermore, one petroleum engineer stated that she was not entirely
aware of what activities the petroleum engineer technicians are
conducting in the field, and that taking the petroleum engineer
technician courses would provide BLM petroleum engineers with greater
insight into measurement and other issues that are addressed on a
daily basis. The lack of training for petroleum engineers can also
limit what functions they may perform. A petroleum engineer told us
that without the training that petroleum engineer technicians receive,
petroleum engineers are unable to issue an Incident of Noncompliance
themselves. Rather, they must work through other staff to have it
issued. Several petroleum engineers also told us they would benefit
from ongoing training, in part, to keep up with the rate at which
technology and processes change in oil and gas fields.
In addition, BLM has experienced high rates of turnover in the
petroleum engineer position. We analyzed Interior data from fiscal
year 2004 through July 2009 for the eight field offices we reviewed
and found that they had overall turnover rates between 33 percent and
100 percent. For example, the Buffalo, Wyoming, field office, which
had an overall turnover rate of 80 percent between fiscal years 2004
and 2008, employed a total of five petroleum engineers, but during
that time period, four individuals in that position either left BLM,
relocated to another field office, or moved to another position within
BLM. Overall, we found that seven of the eight field offices we
reviewed had overall turnover rates of 50 percent or greater during
this time period. According to several petroleum engineers, these high
turnover rates have resulted in the loss of knowledge, skills, and
abilities petroleum engineers accumulate through on-the-job training
and force BLM to repeatedly hire new, often inexperienced petroleum
engineers (see table 10).
Table 10: Total Turnover Rates for Petroleum Engineers, Fiscal Years
2004-2008:
Field office: Buffalo;
Turnover percentage: 80;
Total number of employees in position, FY2004-08: 5;
Total employees leaving position, FY2004-08: 4;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 1 of 3;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 1 of 2;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 1 of 2;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 0 of 2;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 1 of 2;
Average number of employees in position, FY2004-08: 2.
Field office: Carlsbad;
Turnover percentage: 75;
Total number of employees in position, FY2004-08: 4;
Total employees leaving position, FY2004-08: 3;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 1 of 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 0 of 0;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 1 of 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 0 of 3;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 1 of 3;
Average number of employees in position, FY2004-08: 2.
Field office: Farmington;
Turnover percentage: 50;
Total number of employees in position, FY2004-08: 8;
Total employees leaving position, FY2004-08: 4;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 1 of 6;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 0 of 6;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 2 of 6;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 0 of 5;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 1 of 5;
Average number of employees in position, FY2004-08: 6.
Field office: Glenwood Springs;
Turnover percentage: 50;
Total number of employees in position, FY2004-08: 2;
Total employees leaving position, FY2004-08: 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 0 of 0;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 0 of 0;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 0 of 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 0 of 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 1 of 1;
Average number of employees in position, FY2004-08: 1.
Field office: White River;
Turnover percentage: 100;
Total number of employees in position, FY2004-08: 2;
Total employees leaving position, FY2004-08: 2;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 0 of 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 1 of 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 0 of 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 0 of 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 1 of 1;
Average number of employees in position, FY2004-08: 1.
Field office: Pinedale;
Turnover percentage: 100;
Total number of employees in position, FY2004-08: 2;
Total employees leaving position, FY2004-08: 2;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 0 of 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 0 of 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 0 of 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 1 of 2;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 1 of 1;
Average number of employees in position, FY2004-08: 1.
Field office: Roswell;
Turnover percentage: 80;
Total number of employees in position, FY2004-08: 5;
Total employees leaving position, FY2004-08: 4;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 0 of 5;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 0 of 5;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 2 of 5;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 0 of 3;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 2 of 3;
Average number of employees in position, FY2004-08: 4.
Field office: Vernal;
Turnover percentage: 33;
Total number of employees in position, FY2004-08: 6;
Total employees leaving position, FY2004-08: 2;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 0 of 2;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 2 of 3;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 0 of 2;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 0 of 2;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 0 of 4;
Average number of employees in position, FY2004-08: 3.
Source: GAO analysis of Interior data.
Note: We calculated the total turnover rate by (1) counting the number
of individual petroleum engineers who separated from BLM, plus those
who changed locations, plus those who changed from the petroleum
engineer position to another position within that office; (2) dividing
that by the number of individual petroleum engineers employed in each
BLM office from fiscal years 2004 through 2008. For those individuals
who changed jobs or locations, we did not determine whether they
changed jobs or locations because of a management decision, as opposed
to the employees' own decision.
[End of table]
Petroleum Engineer Technicians. BLM has also faced challenges in
hiring, training, and retaining petroleum engineer technicians--staff
critical for inspecting oil and gas sites and ensuring that oil and
gas are measured and reported accurately--over the past 5 years.
According to BLM staff we spoke with, all nine field offices we
reviewed have had difficulty in recruiting staff for petroleum
engineer technician positions. Officials in those offices provided
several reasons, including higher salaries in the private sector
compared with BLM salaries, and the high cost of living in several of
the areas where BLM has offices, including Glenwood Springs, Colorado;
and Pinedale, Wyoming.
Our review of BLM's petroleum engineer technician training program
identified several areas where BLM is experiencing challenges. Once
BLM hires a petroleum engineer technician, BLM has a five-step
training process for ensuring that staff have the knowledge and skills
to understand standard industry practices and BLM's regulatory
requirements. These five steps include the following:
1. Successful completion of BLM's Oil and Gas Compliance Certification
School, which includes six 2-week training modules over the course of
9 months on topics including oil and gas measurement, reviewing
production records, and technical aspects of drilling and plugging oil
and gas wells.
2. On-the-job training developed and conducted by the petroleum
engineer technician's state office.
3. Passing a technical review exam, which successfully demonstrates
the petroleum engineer technician's skills and knowledge in performing
a field inspection.
4. Official Certification by the State Director, based on the
recommendation by the National Lead for Certification and Training.
5. Maintain basic competency through successfully completing the
Compliance Certification course once every 5 years.
However, until fiscal year 2010, BLM was limited in its ability to
provide timely training, as it was unable to accommodate all petroleum
engineer technicians who attempted to complete step 1, or enroll in
the annual training course. This led to a training backlog for newly
hired staff. A BLM official provided several reasons for not being
able to accommodate the additional demand, including the need to limit
the course to 25 people to ensure effective instruction in the field,
and a lack of instructors for a second session for each of the
modules. As a result of the backlog, however, petroleum engineer
technicians who were unable to attend the training remained limited in
their ability to independently complete production inspections.
Rather, according to some senior petroleum engineer technicians, they
had to devote additional time to providing on-the-job training and
supervising new petroleum engineer technicians, which had the added
effect of limiting the senior petroleum engineer technicians' ability
to complete their own inspections. According to a BLM training
coordinator, fiscal year 2010 is the first time that BLM does not have
a backlog since this six-module training course has been offered.
Moreover, because BLM has experienced difficulty in recruiting
individuals with prior oil and gas training, many newly hired staff
have been unable to complete the six pass/fail modules. According to
BLM data, only 61 percent of petroleum engineer technicians initially
enrolled in the course eventually pass (see table 11).
Table 11: Overview of Course Petroleum Engineer Technician Attendees
by Fiscal Years 2003-2008:
Fiscal year: 2003/2004;
Number of students selected for module 1: 25;
Number of students attending module 1: 25;
Number of students completing modules 1 - 6: 16.
Fiscal year: 2005;
Number of students selected for module 1: 25;
Number of students attending module 1: 25;
Number of students completing modules 1 - 6: 24.
Fiscal year: 2006;
Number of students selected for module 1: 20;
Number of students attending module 1: 17;
Number of students completing modules 1 - 6: 13.
Fiscal year: 2007;
Number of students selected for module 1: 25;
Number of students attending module 1: 22;
Number of students completing modules 1 - 6: 16.
Fiscal year: 2008;
Number of students selected for module 1: 25;
Number of students attending module 1: 25;
Number of students completing modules 1 - 6: 19[A].
Fiscal year: 2009;
Number of students selected for module 1: 25;
Number of students attending module 1: 19;
Number of students completing modules 1 - 6: TBD.
Fiscal year: Total;
Number of students selected for module 1: 145;
Number of students attending module 1: 133;
Number of students completing modules 1 - 6: 88.
Fiscal year: Percentage;
Number of students selected for module 1: 100;
Number of students attending module 1: 92;
Number of students completing modules 1 - 6: 61.
Source: BLM.
[A] Two students did not pass Modules 2 and/or 3 and will attend
modules in fiscal year 2009 to raise their scores to a passing grade.
[End of table]
Another area where BLM has been unable to meet its training policy
standards is in ensuring that certified petroleum engineer technicians
are provided maintenance training. According to BLM's petroleum
engineer technician Certification Policy, staff must demonstrate their
continued competence in completing inspections once every 5 years.
According to a BLM official, this is necessary as industry practices
and technologies change over time and additional training may be
necessary. BLM created a course specifically for this purpose;
however, it has not been offered since 2002, meaning that under BLM's
own policy, some staff may be out of compliance.
Finally, turnover of petroleum engineer technician staff at the field
office level continues to be high. In reviewing BLM data for petroleum
engineer technicians who completed all six training modules, many of
the petroleum engineer technicians have either moved on to other
positions within BLM or left the agency altogether. Specifically, of
the petroleum engineer technicians who completed the training modules,
7 percent have taken positions in other areas within BLM and another
13 percent have left BLM. The combined result of this are that BLM has
foregone expenditures for recruiting, hiring, and training staff
approximately 20 percent of the time (see table 12).
Table 12: Overview of Course Petroleum Engineer Technician Attendees
by Fiscal Years 2003-2008:
Fiscal year: 2003/2004;
Students completing modules 1 - 6: 16;
Petroleum Engineer Technicians who moved to other BLM jobs: 0;
Petroleum Engineer Technicians who left BLM after completing modules
1 - 6: 3.
Fiscal year: 2005;
Students completing modules 1 - 6: 24;
Petroleum Engineer Technicians who moved to other BLM jobs: 1;
Petroleum Engineer Technicians who left BLM after completing modules
1 - 6: 4.
Fiscal year: 2006;
Students completing modules 1 - 6: 13;
Petroleum Engineer Technicians who moved to other BLM jobs: 4;
Petroleum Engineer Technicians who left BLM after completing modules
1 - 6: 2.
Fiscal year: 2007;
Students completing modules 1 - 6: 16;
Petroleum Engineer Technicians who moved to other BLM jobs: 1;
Petroleum Engineer Technicians who left BLM after completing modules
1 - 6: 2.
Fiscal year: 2008;
Students completing modules 1 - 6: 19[A];
Petroleum Engineer Technicians who moved to other BLM jobs: 0;
Petroleum Engineer Technicians who left BLM after completing modules
1 - 6: 0.
Fiscal year: Total;
Students completing modules 1 - 6: 88;
Petroleum Engineer Technicians who moved to other BLM jobs: 6;
Petroleum Engineer Technicians who left BLM after completing modules
1 - 6: 11.
Source: BLM.
[A] Two students did not pass Modules 2 and/or 3 and will attend
modules in fiscal year 2009 to raise their scores to a passing grade.
[End of table]
Furthermore, our analysis of petroleum engineer technician turnover
data at the field office level indicates that five of the nine field
offices we reviewed had an overall turnover rate in excess of 50
percent between fiscal years 2004 and 2008. Moreover, some of this
turnover occurred in field offices that have very high oil and gas
production. For example, the Pinedale, Wyoming, field office which, in
recent years, has had more production of federal gas than any other
field office, had an overall turnover rate of 83 percent between
fiscal years 2004 and 2008. Specifically, during this period, the
Pinedale, Wyoming, field office employed 12 petroleum engineer
technicians in that position, but during that time 10 individuals in
that position either left BLM, relocated to another field office, or
moved to another position within BLM. According to staff in the
Pinedale, Wyoming, field office, turnover has added to already
existing challenges in verifying production (see table 13).
Table 13: Total Turnover Rates for Petroleum Engineer Technicians,
Fiscal Years 2004-2008:
Field office: Buffalo;
Turnover percentage: 30;
Total number of employees in position, FY2004-08: 20;
Total employees leaving position, FY2004-08: 6;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 1 of 12;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 0 of 12;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 2 of 13;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 2 of 14;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 1 of 15;
Average number of employees in position, FY2004-08: 13.
Field office: Carlsbad;
Turnover percentage: 47;
Total number of employees in position, FY2004-08: 19;
Total employees leaving position, FY2004-08: 9;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 1 of 10;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 1 of 9;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 4 of 9;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 1 of 10;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 2 of 12;
Average number of employees in position, FY2004-08: 10.
Field office: Farmington;
Turnover percentage: 54;
Total number of employees in position, FY2004-08: 37;
Total employees leaving position, FY2004-08: 20;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 1 of 22;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 3 of 25;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 7 of 24;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 3 of 21;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 6 of 22;
Average number of employees in position, FY2004-08: 23.
Field office: Glenwood Springs;
Turnover percentage: 67;
Total number of employees in position, FY2004-08: 3;
Total employees leaving position, FY2004-08: 2;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 0 of 0;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 0 of 0;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 0 of 0;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 0 of 2;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 2 of 3;
Average number of employees in position, FY2004-08: 3.
Field office: Hobbs;
Turnover percentage: 22;
Total number of employees in position, FY2004-08: 9;
Total employees leaving position, FY2004-08: 2;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 2 of 8;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 0 of 6;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 0 of 6;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 0 of 6;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 0 of 6;
Average number of employees in position, FY2004-08: 6.
Field office: White River;
Turnover percentage: 55;
Total number of employees in position, FY2004-08: 11;
Total employees leaving position, FY2004-08: 6;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 1 of 2;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 2 of 3;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 0 of 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 1 of 2;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 2 of 7;
Average number of employees in position, FY2004-08: 3.
Field office: Pinedale;
Turnover percentage: 83;
Total number of employees in position, FY2004-08: 12;
Total employees leaving position, FY2004-08: 10;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 1 of 2;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 1 of 6;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 2 of 6;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 3 of 5;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 3 of 5;
Average number of employees in position, FY2004-08: 5.
Field office: Roswell;
Turnover percentage: 57;
Total number of employees in position, FY2004-08: 7;
Total employees leaving position, FY2004-08: 4;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 0 of 4;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 0 of 4;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 1 of 4;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 1 of 4;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 2 of 5;
Average number of employees in position, FY2004-08: 4.
Field office: Vernal;
Turnover percentage: 17;
Total number of employees in position, FY2004-08: 18;
Total employees leaving position, FY2004-08: 3;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 1 of 13;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 1 of 14;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 1 of 13;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 0 of 15;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 0 of 15;
Average number of employees in position, FY2004-08: 14.
Source: GAO analysis of Interior data.
Note: We calculated the total turnover rate by (1) counting the number
of individual petroleum engineer technicians who separated from BLM,
plus those who changed locations, plus those who changed from the
petroleum engineer technician position to another position within that
office; (2) dividing that by the number of individual petroleum
engineer technicians employed in each BLM office from fiscal years
2004 through 2008. For those individuals who changed jobs or
locations, we did not determine whether they changed jobs or locations
because of a management decision, as opposed to the employees' own
decision.
[End of table]
BLM Production Accountability Technicians. BLM's production
accountability technician position has experienced several of the same
challenges that both petroleum engineer and petroleum engineer
technician positions have. Production accountability technicians in
five of the seven field offices we visited generally stated that there
had been difficulties in hiring production accountability technicians.
According to these staff, production accountability technicians are
hired at a pay level below that of petroleum engineer technicians.
Also, the low salary has made it difficult for BLM to attract people
with the necessary skills to perform the responsibilities of the job.
Moreover, BLM has not provided production accountability technicians
with sufficient training once they are hired. Production
accountability technician work is technically complicated in that they
review and corroborate oil and gas quality and volume data from a
variety of sources. These sources include data generated by electronic
flow computers, gas analysis reports, calibration reports, and monthly
production records. Because their reviews are conducted on a case
level, the total number of wells reviewed may be in the hundreds.
According to a BLM training coordinator, BLM has offered three
production accountability technician training sessions over the past 5
years; one in 2004, another in 2006 and, most recently, in 2009. This
most recent session was 3 days which, according to the training
coordinator, was not long enough to cover all the relevant material.
Additionally, we found during our site visits that in some instances,
little training or guidance is provided to production accountability
technicians upon being hired. In one instance, a production
accountability technician was hired by a field office that previously
did not have other production accountability technicians. According to
the production accountability technician, she learned most of her job
responsibilities on the job with little oversight. In another field
office, a production accountability technician who had been employed
for over 3 years and had not yet received formal training reported
having only recently completed her first gas audit.
Finally, our analysis of production accountability technicians shows
that eight of the nine field offices we reviewed had an overall
turnover rate of 50 percent or more between fiscal years 2004 thorough
2008. Also, similar to the petroleum engineer and petroleum engineer
technician turnover rates for the Pinedale, Wyoming, field office, the
production accountability technician turnover rate in that field
office was high, as well, with an overall turnover rate of 100 percent
between fiscal years 2004 and 2008 (see table 14). Specifically, the
Pinedale, Wyoming, field office employed a total of three production
accountability technicians in that position; but during that time,
three individuals in that position either left BLM, relocated to
another field office, or moved to another position within BLM.
Table 14: Total Turnover Rates for Production Accountability
Technicians, Fiscal Years 2004-2008:
Field office: Buffalo;
Turnover percentage: 75;
Total number of employees in position, FY2004-08: 8;
Total employees leaving position, FY2004-08: 6;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 0 of 2;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 0 of 2;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 0 of 2;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 3 of 4;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 3 of 5;
Average number of employees in position, FY2004-08: 3.
Field office: Carlsbad;
Turnover percentage: 67;
Total number of employees in position, FY2004-08: 3;
Total employees leaving position, FY2004-08: 2;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 1 of 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 0 of 0;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 0 of 0;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 0 of 0;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 1 of 2;
Average number of employees in position, FY2004-08: 2.
Field office: Farmington;
Turnover percentage: 63;
Total number of employees in position, FY2004-08: 8;
Total employees leaving position, FY2004-08: 5;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 0 of 3;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 1 of 4;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 0 of 3;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 2 of 5;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 2 of 5;
Average number of employees in position, FY2004-08: 4.
Field office: Glenwood Springs;
Turnover percentage: 0;
Total number of employees in position, FY2004-08: 1;
Total employees leaving position, FY2004-08: 0;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 0 of 0;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 0 of 0;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 0 of 0;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 0 of 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 0 of 1;
Average number of employees in position, FY2004-08: 1.
Field office: Hobbs;
Turnover percentage: 50;
Total number of employees in position, FY2004-08: 4;
Total employees leaving position, FY2004-08: 2;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 0 of 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 0 of 2;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 0 of 2;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 2 of 4;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 0 of 2;
Average number of employees in position, FY2004-08: 2.
Field office: White River;
Turnover percentage: 50;
Total number of employees in position, FY2004-08: 2;
Total employees leaving position, FY2004-08: 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 0 of 0;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 0 of 0;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 0 of 0;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 1 of 2;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 0 of 1;
Average number of employees in position, FY2004-08: 2.
Field office: Pinedale;
Turnover percentage: 100;
Total number of employees in position, FY2004-08: 3;
Total employees leaving position, FY2004-08: 3;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 0 of 0;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 0 of 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 0 of 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 1 of 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 2 of 2;
Average number of employees in position, FY2004-08: 1.
Field office: Roswell;
Turnover percentage: 100;
Total number of employees in position, FY2004-08: 1;
Total employees leaving position, FY2004-08: 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 1 of 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 0 of 0;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 0 of 0;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 0 of 0;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 0 of 0;
Average number of employees in position, FY2004-08: 1.
Field office: Vernal;
Turnover percentage: 50;
Total number of employees in position, FY2004-08: 2;
Total employees leaving position, FY2004-08: 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 1 of 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 0 of 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 0 of 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 0 of 2;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 0 of 2;
Average number of employees in position, FY2004-08: 1.
Source: GAO analysis of Interior data.
Note: We calculated the total turnover rate by (1) counting the number
of individual production accountability technicians who separated from
BLM, plus those who changed locations, plus those who changed from the
production accountability technician position to another position
within that office; (2) dividing that by the number of individual
production accountability technicians employed in each BLM office from
fiscal years 2004 through 2008. For those individuals who changed jobs
or locations, we did not determine whether they changed jobs or
locations because of a management decision, as opposed to the
employees' own decision.
[End of table]
OEMM Petroleum Engineers. Offshore, OEMM's ability to hire high-
quality applicants for offshore engineers was described as very
difficult in the past; however, according to one OEMM official, the
recent economic downturn has increased the number and quality of the
candidates applying for these positions. However, the official added
that retaining individuals within the unit who approve measurement
applications can be challenging, because of the difficult nature of
the work and the lure of other opportunities within or outside MMS.
OEMM petroleum engineers who review measurement applications at the
regional level, according to an OEMM official, are not required to
receive specific training or to meet a minimum level of proficiency in
measurement issues. Unlike BLM, OEMM does not have a specific training
course for its petroleum engineer staff who review applications for
oil and gas measurement. However, OEMM petroleum engineer staff
receive individualized training for their work reviewing measurement,
commingling, and allocation applications from oil and gas producers.
This training includes classes provided both by OEMM and by external
vendors, such as universities and private providers of measurement
training. Training plans are assigned to OEMM engineers on a case-by-
case basis, and generally fit the needs of the particular engineering
staff member. In addition, a large portion of OEMM petroleum engineers
in the Gulf of Mexico region hold degrees in petroleum engineering,
according to OEMM officials. For the three district offices we
reviewed that were in the Gulf of Mexico region, production
measurement applications are reviewed at the regional level by a staff
of seven petroleum engineers. Of those, five of the seven petroleum
engineers hold petroleum engineering degrees, either at the Bachelor's
or the Master's level. In OEMM's Pacific region, geoscientists handle
measurement approvals.
According to OEMM officials and human capital data we reviewed, the
petroleum engineering staff who review offshore measurement do not
appear to have turnover rates that are impeding program operations. We
found that the overall turnover rates for petroleum engineers for the
OEMM Gulf of Mexico and Pacific regional offices--which handle
measurement approvals at the regional level of the four district
offices we reviewed--had overall turnover rates of 30 percent or less
(see table 15).
Table 15: Total Turnover Rates for OEMM Petroleum Engineers[A] who
Approve Measurement, Fiscal Years 2004-2008:
Regional office: Gulf of Mexico region;
Turnover percentage: 30;
Total number of employees in position, FY2004-08: 10;
Total employees leaving position, FY2004-08: 3;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 0 of 8;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 1 of 7;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 2 of 6;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 0 of 7;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 0 of 7;
Average number of employees in position, FY2004-08: 7.
Regional office: Pacific region;
Turnover percentage: 0;
Total number of employees in position, FY2004-08: 1;
Total employees leaving position, FY2004-08: 0;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 0 of 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 0 of 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 0 of 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 0 of 1;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 0 of 1;
Average number of employees in position, FY2004-08: 1.
Source: GAO analysis of Interior data.
Note: We calculated the total turnover rate by (1) counting the number
of individual OEMM petroleum engineers who separated from OEMM, plus
those who changed locations, plus those who changed from the petroleum
engineer position to another position within that office; (2) dividing
that by the number of individual petroleum engineers employed in each
OEMM office from fiscal years 2004 through 2008. For those individuals
who changed jobs or locations, we did not determine whether they
changed jobs or locations because of a management decision, as opposed
to the employees' own decision.
[A] In OEMM's Pacific region, geoscientists handle measurement
approvals.
[End of table]
OEMM Inspectors. Inspectors in three of the four district offices we
spoke with told us hiring new inspectors has been difficult. Not only
does OEMM compete with the private sector, but there is also a long
medical testing process for inspectors, which must be passed before
inspectors can be hired on a permanent basis. This process can take
from four to six months and involves rigorous training to prepare for
possible helicopter accidents. This training is considered to be so
critical that until inspectors successfully complete the medical
testing--which involves being dropped into a tank of water to simulate
an accident--they cannot conduct inspections. According to the
inspectors we spoke with, a few individuals were unable to pass the
medical testing and were, therefore, delayed prior to becoming
inspectors. New inspectors who do not pass the test the first time can
be delayed for several months until they can pass the test.
Offshore inspectors at OEMM district offices do not have a required,
standardized measurement training curriculum. While OEMM inspectors
are required to take a minimum of 60 hours of training every 2 years,
including courses on safety and other basic issues, they are not
required to take specialized training in measurement issues. OEMM
officials in each of the four OEMM district offices we reviewed told
us that measurement issues are complex, and that new inspectors can
take from several months to 18 months, to become proficient at
measurement inspections, depending on their level of prior experience
and expertise. Some inspectors also told us that there is generally at
least one inspector in the district office with more knowledge of
measurement issues than the other inspectors and this inspector would
be able to assist the others in addressing measurement issues in the
field, which is done on an informal basis. In discussions with OEMM
inspectors and officials, we were told that inspectors have the option
of training in a variety of issues, such as platform operations,
drilling, completion, and measurement issues. Furthermore, the
inspectors told us that the training provided to new inspectors should
depend on their experience. OEMM provides its inspectors with training
through either on-the-job training, internal courses, or external
courses, such as those offered by the University of Oklahoma's
International School of Hydrocarbon Measurement or by private experts.
Starting in 2009, one OEMM region, the Gulf of Mexico region,
developed an internal measurement training presentation and gave it to
inspectors at all district offices in the Gulf of Mexico region. At
another OEMM regional office, an official told us that inspectors in
their office do not have a standardized curriculum and that external
measurement training is offered on an individual basis. Finally, OEMM
inspectors told us that the time experienced inspectors spend training
new inspectors reduces the amount of time that otherwise would be
spent conducting inspections.
In addition, OEMM does not evaluate the extent of new inspectors'
knowledge of measurement issues. During our discussions with offshore
inspectors, we were told that new OEMM inspectors often have
experience as offshore platform operators, which often involves some
knowledge of measurement issues. OEMM officials also explained that,
until the early 1990s, OEMM measurement inspections in the Gulf of
Mexico region were performed by a measurement inspection team, based
out of the regional office, of petroleum engineers who review and
approve measurement systems. However, OEMM delegated the measurement
inspection responsibilities to the district offices in order to cut
costs, because the cost of flying to offshore platforms is cheaper and
less time-intensive from the various district offices than flying from
the regional office. While many of these measurement inspectors
continue to be employed in OEMM district offices, OEMM does not
formally identify the extent to which inspectors are proficient in
measurement or identify what skills, experience, and training are
necessary for this proficiency. Without a formal curriculum for
measurement issues or a formal plan to ensure that inspectors are
proficient in measurement, OEMM's seven district offices are at risk
for not having the necessary measurement expertise to identify
problems on offshore platforms.
Finally, we conducted an analysis of overall turnover rates for OEMM
inspection staff for fiscal years 2004 through 2008 for the four
district offices that we reviewed. This data shows that there was an
overall turnover rate of between 27 and 44 percent for those 5 years
(see table 16). For example, the California district office had an
overall rate of 44 percent turnover, based on the four inspectors who
left the position over those 5 years; the Lake Jackson, Texas,
district office had an overall rate of 27 percent turnover. While
turnover among OEMM inspectors generally occurred at lower rates than
for BLM offices, offshore inspection staff and supervisors told us
that turnover can still have a disruptive impact on their work.
Inspectors in one district office told us that they had lost three
experienced inspectors in fiscal years 2009 and 2010,[Footnote 63] due
to significant pay differences between private industry and OEMM.
Table 16: Total Turnover Rates for OEMM Inspectors, Fiscal Years 2004-
2008:
District office: New Orleans;
Turnover percentage: 42;
Total number of employees in position, FY2004-08: 19;
Total employees leaving position, FY2004-08: 8;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 1 of 13;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 0 of 13;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 2 of 13;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 3 of 14;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 2 of 13;
Average number of employees in position, FY2004-08: 13.
District office: Lake Jackson;
Turnover percentage: 27;
Total number of employees in position, FY2004-08: 11;
Total employees leaving position, FY2004-08: 3;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 0 of 9;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 0 of 11;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 2 of 11;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 0 of 9;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 1 of 9;
Average number of employees in position, FY2004-08: 10.
District office: Lake Charles;
Turnover percentage: 41;
Total number of employees in position, FY2004-08: 17;
Total employees leaving position, FY2004-08: 7;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 2 of 15;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 0 of 13;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 0 of 13;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 1 of 13;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 4 of 14;
Average number of employees in position, FY2004-08: 14.
District office: California;
Turnover percentage: 44;
Total number of employees in position, FY2004-08: 9;
Total employees leaving position, FY2004-08: 4;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2004: 0 of 7;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2005: 2 of 9;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2006: 0 of 7;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2007: 1 of 7;
Total employees leaving position, FY2004-08 (of the number employed in
that fiscal year): 2008: 1 of 6;
Average number of employees in position, FY2004-08: 7.
Source: GAO analysis of Interior data.
Note: We calculated the total turnover rate by (1) counting the number
of individual inspectors who separated from OEMM, plus those who
changed locations, plus those who changed from the inspector position
to another position within that office; (2) dividing that by the
number of individual inspectors employed in each OEMM district office
from fiscal years 2004 through 2008. For those individuals who changed
jobs or locations, we did not determine whether they changed jobs or
locations because of a management decision, as opposed to the
employees' own decision.
[End of table]
MMS's Liquid Verification System and Gas Verification System Staff.
MMS added about 10 additional staff to work on its Liquid Verification
System and Gas Verification System programs in fiscal year 2009, after
relocating the Gas Verification System discrepancy resolution function
from the OEMM New Orleans office to its MMS Lakewood, Colorado,
office. According to a MMS official in charge of the Liquid and Gas
Verification systems, the training provided to technicians is specific
to their work, which focuses on resolving detected volume
discrepancies between reported volumes and the volumes shown on meter
statements that MMS' computer system automatically detects. In recent
years, the Liquid and Gas Verification systems have detected a number
of discrepancies, some of which MMS staff have not yet been able to
resolve, creating a backlog. Since MMS added additional staff to the
Liquid and Gas Verification systems program, MMS is showing progress
in eliminating its backlog of discrepancies and has a goal of
eliminating this backlog by mid-2010.
Turnover of Liquid and Gas Verification system program staff for
fiscal years 2004 through 2008 remained low, however, staffing levels
were low during this period as well, with one person each assigned to
the Liquid Verification system and Gas Verification system,
respectively. The workload for resolving discrepancies identified by
both systems was greater than the staffing levels were able to
maintain, and a large backlog of exceptions developed (see table 17).
Table 17: Number of Liquid Verification System (LVS) and Gas
Verification System (GVS) analysts, Fiscal Years 2004-2009:
Fiscal year: 2004;
LVS analysts: 1;
GVS analysts: n/a.
Fiscal year: 2005;
LVS analysts: 1;
GVS analysts: 1.
Fiscal year: 2006;
LVS analysts: 1;
GVS analysts: 1.
Fiscal year: 2007;
LVS analysts: 1;
GVS analysts: 1.
Fiscal year: 2008;
LVS analysts: 2;
GVS analysts: 1.
Fiscal year: 2009;
LVS analysts: 5;
GVS analysts: 9.
Source: GAO analysis of Interior data.
[End of table]
[End of section]
Appendix V: Production Verification Tools and Practices Used by
Selected States, Companies, and Other Countries:
We identified four oil and gas production verification tools and
practices used by other states, private companies, and other countries
that are not widely employed by Interior, including (1) establishing
uncertainty thresholds for oil and gas measurement, (2) using
electronic tools to monitor oil and gas production, (3) requiring
senior oil and gas company officials to annually attest to the
controls for oil and gas measurement, and (4) balancing volumes of oil
and gas systemwide.
Some Countries Rely on Established Thresholds for Oil and Gas
Measurement Uncertainty at Critical Points to Ensure Measurement is
Reasonably Accurate:
While Interior has established measurement uncertainty limits for
onshore gas, several countries have established standards for both oil
and gas, providing greater assurance that oil and gas are accurately
measured. Measurement uncertainty is determined through a calculation
that incorporates the uncertainty for each component of the
measurement system, thereby resulting in an overall uncertainty
measurement. These components may include the meter, meter
calibration, and sample gathering and analysis, among others. For
example, to calculate the measurement uncertainty for gas at a single
point, accuracies for the meter device, transducers, calibration,
electronic flow computer calculations, and gas sampling are combined
to determine the overall uncertainty. So, according to research
conducted by Alberta, Canada's regulatory agency, a typical
uncertainty calculation for natural gas at a delivery point might look
like the following:
Primary measurement device - gas meter uncertainty: = 1.00%.
Primary measurement device - gas meter uncertainty: Secondary device-
(transducer) uncertainty; = 0.5%.
Primary measurement device - gas meter uncertainty: Secondary device
calibration; = 0.5%.
Primary measurement device - gas meter uncertainty: Tertiary device
(electronic flow computer) uncertainty; = 0.2%.
Primary measurement device - gas meter uncertainty: Gas Sampling and
analysis uncertainty; = 1.5%.
Primary measurement device - gas meter uncertainty: Combined
uncertainty [A]; = 1.95%.
[A] The combined uncertainty equals the square root of [(1.0)^2 +
(0.5)^2 + (0.5)^2 + (0.2)^2 + (1.5)^2]
[End of table]
Similarly, uncertainty calculations may be applied to oil. To
calculate the overall uncertainty for oil, uncertainty data for the
oil meter, meter proving uncertainty, and the basic sediment and water
determination are combined to determine the overall uncertainty. Our
review of selected other regulatory agencies indicate that uncertainty
standards have been incorporated into their measurement guidance.
Specifically, four of the other entities we reviewed have measurement
uncertainty standards (see table 18).
Table 18: Establishment of Uncertainty Standards in Selected Entities'
Measurement Guidance:
Gas:
OEMM: No;
BLM: Yes;
Alberta: Yes;
Norway: Yes;
Labrador/Nova Scotia: Yes;
United Kingdom: Yes.
Oil:
OEMM: No;
BLM: No;
Alberta: Yes;
Norway: Yes;
Labrador/Nova Scotia: Yes;
United Kingdom: Yes.
Source: GAO analysis.
[End of table]
As we mentioned, Interior has only established uncertainty standards
for onshore gas measurement. This standard was established through
Notices to Lessees issued by BLM state offices addressing electronic
flow computers issued between 2004 and 2008, though the standard was
referenced in both the 1994 and 1998 gas measurement draft
regulations. The BLM state policies generally say that, for meters
measuring more than 100 thousand cubic feet (mcf) per day on a monthly
basis, the electronic flow computer should be installed, operated, and
maintained to achieve an overall measurement uncertainty of +/-3
percent or better. According to a BLM official, BLM arrived at the 3
percent threshold around 1990, when it reasoned that an appropriate
threshold would approximate the worst-case conditions allowed for a
chart recorder under its gas measurement regulations. Until 2006,
however, BLM staff could not easily enforce this requirement because
manually calculating uncertainties is technically difficult. It was
not until BLM--in conjunction with an independent flow measurement
lab--developed an uncertainty calculator that BLM staff were able to
more easily calculate gas measurement uncertainties. OEMM has not
established uncertainty thresholds for oil or gas and staff
acknowledged that they were not entirely comfortable with the
application of uncertainty standards at this time. Rather, they rely
on operators following regulations that should provide reasonably
accurate measurement--though the accuracy is not specifically
quantified in any policy or regulation.
Our review of four other regulatory jurisdictions found that they all
had established measurement uncertainty standards for both oil and
gas. Specifically, Norway; the United Kingdom; and the provinces of
Labrador/Nova Scotia, and Newfoundland, Canada, have adopted a 1
percent measurement uncertainty for gas produced offshore, whereas
Alberta, Canada, established a 2 percent measurement uncertainty limit
for its onshore gas--1 percentage point lower than BLM's standard for
onshore gas. Additionally, each of the other jurisdictions established
measurement uncertainty standards for oil--ranging from a low of 0.25
percent for the United Kingdom and certain Canadian provinces, to a
high of 1.00 percent for low volume custody transfer points in Alberta
(see table 19).
Table 19: Entities Where Percentage Uncertainty Standards Are
Incorporated Into Measurement Guidance:
Gas sales/custody transfer point;
OEMM - offshore: N/A;
BLM - onshore: 3.00;
Alberta - onshore: 2.00;
Norway - offshore: 1.00;
Labrador/Nova Scotia/Newfoundland-offshore: 1.00;
United Kingdom - offshore: 1.00.
Oil sales/custody transfer point - low volume;
OEMM - offshore: N/A;
BLM - onshore: N/A;
Alberta - onshore: 1.00;
Norway - offshore: 0.30;
Labrador/Nova Scotia/Newfoundland-offshore: 0.25;
United Kingdom - offshore: 0.25.
Oil sales/custody transfer point - high volume;
OEMM - offshore: N/A;
BLM - onshore: N/A;
Alberta - onshore: 0.50;
Norway - offshore: 0.30;
Labrador/Nova Scotia/Newfoundland-offshore: 0.25;
United Kingdom - offshore: N/A.
Source: GAO analysis.
[End of table]
According to documents and discussions with regulatory officials in
other countries, they adopted measurement uncertainty standards in
their countries for several reasons. For example, Norwegian regulators
told us that, previously, they approved all measurement designs, which
was both time-consuming and costly. In 1991, the regulations were
revised so that regulatory officials would not approve, but provide
consent to the company-proposed measurement system. To assist industry
in determining what types of measurement methods would be sufficient,
Norway incorporated uncertainty limits for oil and gas measurement.
Alberta's Energy Resources Conservation Board first established
uncertainty standards in 1972, when it concluded the need to establish
production accuracy standards for pooled oil and gas. The standards
have evolved since they were established, but still require that
measurement at delivery or sales points meet the highest accuracy
standards because volumes determined at those points have a direct
impact on royalty determination.
Oil and Gas Companies and Some States Use Electronic Tools to Monitor
Oil and Gas Production:
Some oil and gas companies and state regulators use electronic tools
not widely used by Interior for federal leases including: (1) using
integrated software to monitor production in real time, (2) using
electronic tools to document inspections in the field, and (3) using
similar software packages to facilitate audits between purchasers and
sellers.
Oil and Gas Companies Use Integrated Software Tools to Monitor Oil and
Gas Production in Real Time:
Each of the eight production operators and gas pipeline companies that
we spoke with during the course of our review use sophisticated
electronic Supervisory Control and Data Administration (SCADA) systems
of electronic sensors and computer software to track production and
transportation of oil and natural gas. According to these company
officials, SCADA systems enable them to monitor the amount of oil and
gas produced and transported on a daily, hourly, or an instantaneous
basis. In addition, SCADA systems provide the ability to be
automatically alerted if there are problems with production, such as
an interruption of production or damaged metering equipment.
SCADA systems typically gather information about oil and gas
production from electronic sensors in the field that measure oil or
gas volumes, such as electronic flow computers on gas meters or
special electronic sensors within oil tanks. They then collect and
transmit that information through a variety of means, such as direct
line of sight radio transmissions or transmissions via a cellular
network. These production data are then compiled by computers at
production operators' and transporters' offices and compiled by
computers. The computers that receive this data can then use software
packages to calculate, display, and report the oil and gas volumes
that are flowing through various points of measurement.
SCADA systems allow production companies to carry out their production
activities more efficiently. For example, onshore wells often produce
liquid oil and gas that can be sold in association with underground
wastewater, which must be disposed. While the gas is sent down a
pipeline, the liquid oil and water are stored in tanks that must be
drained periodically by trucks; the trucks then deliver the oil to
refineries and the water to wastewater disposal facilities. Without a
SCADA monitoring system installed in the oil and wastewater tanks,
onshore production companies would not know when their tanks are full
enough to be pumped out, otherwise they would need to send trucks to
pump the tanks out whether or not they were full--resulting in wasted
driving time and additional trips. However, if a SCADA system were
installed in oil and wastewater tanks, companies could wait to send
trucks until the tanks are full enough to be pumped out.
SCADA systems allow companies to report their oil and gas measurement
data more easily. According to company officials we spoke with,
software packages are available that can receive and interpret SCADA
data, as well as automatically prepare standard reports on oil and gas
production and transportation for a variety of time frames--such as
daily, monthly, and annually. One software maker we spoke with told us
that their systems are capable of producing reports in a variety of
electronic formats for use by the entities that receive the reports.
Some States Use Electronic Tools for Inspections and to Collect and
Report Production Data:
Some of the state governments in our review used software tools to
inspect oil and gas wells in their state.[Footnote 64] For example, 5
of the 10 states that we reviewed told us that their inspectors used
software tools on laptop computers to complete their inspections,
either for production accountability or for other inspections, such as
checking whether the well is producing, or to ensure that
environmental damage was not occurring. For example, in New Mexico,
inspectors enter data into notebook computers in the field when they
perform inspections, using the state's Risk-Based Data Management
System (RBDMS).[Footnote 65] This system minimizes the amount of work
required to capture environmental and groundwater inspection data in
the field and then uploads that data to other computer systems.
According to New Mexico state officials, two BLM field offices have
purchased laptops from New Mexico equipped with the RBDMS system in
order to evaluate them for use by BLM inspectors.
Finally, all of the states in our review publicly provided production
information on the Web for oil and gas production data for wells in
their state, including wells producing on state, private, and federal
leases. For example, Louisiana's Strategic Online Natural Resources
Information System provides geospatial information showing the
production of wells by location. The Wyoming Oil and Gas Conservation
Commission provides information about oil and production on its Web
site,[Footnote 66] which can be retrieved by searching for individual
oil and gas wells, by geographic location, or by the name of the
production operator. For more information on the production
accountability practices of state governments, see appendix VI.
Companies Audit One Another More Easily by Using Similar Software
Packages:
Additionally, oil and gas companies routinely perform audits of
measurement systems. This process can be completed more quickly and
easily when they use similar software packages and data formats.
According to industry officials at six of the eight companies we
reviewed, audits of oil and gas companies are a common activity in the
oil and gas industry; for example, many contracts between production
operators and pipeline transporters include clauses that allow the
transfer of data and audits. For example, according to an oil and gas
auditor, oil and gas companies audit the transportation pipeline
companies that purchase or deliver oil and gas they produce to ensure
that the volumes they are producing are accurate. In addition, private
companies can also conduct internal audits of their own systems, which
provide company management with reasonable assurance that their own
measurement and production verification systems are working adequately.
Similar software packages enable many private companies to complete
their audits more quickly, according to several of the companies we
spoke with. When companies use similar data and analytical tools, then
the companies are able to use their software tools to more quickly
interpret measurement data. For example, officials from one company
told us that similar software tools allow the companies auditing its
measurement to share or swap data from meters that measure the same
flow--so that the auditing company can easily determine whether there
are any problems.
In addition, similar software packages allow the audited company to
provide both the edited data that they reported and the "raw,"
unedited data. Editing raw meter data for reporting purposes is also a
common part of reporting oil and gas measurement because many
irregularities are possible in unedited data--such as a temporary
electronic failure, interruptions in data due to meter servicing,
intermittent production, or other problems. However, it is common for
the private companies in our review to make available the raw,
unedited data for audit and examination by other companies. Although
there can be many different formats for raw data and because there are
many different manufacturers of meters and SCADA systems, software
packages exist that can interpret different data formats. In addition,
one software company official we spoke with told us that meter
manufacturers are moving toward a common data format.
Canada's Alberta Province Requires Senior Oil and Gas Company
Management to Attest to Internal Controls over Measurement and
Reporting, with a Goal of Providing Greater Assurance of Measurement
and Reporting Accuracy:
Canada's Alberta province Energy Resources Conservation Board (ERCB),
the agency that regulates Alberta's oil and gas development, has
recently established a requirement that oil and gas operators' senior
executives must annually attest to the state of their compliance with
ERCB measurement and reporting requirements. According to ERCB's
Enhanced Production Audit Program (EPAP) officials, Alberta's Auditor
General's 2004 to 2005 annual report raised concerns about ERCB's
inability to provide an appropriate level of assurance over the
accuracy of oil and gas measurement and the completeness of oil and
gas production volumes submitted by operators. According to EPAP
officials, up to this time, ERCB had relied on conducting substantive
audits for a small number of facilities each year. According to these
officials, substantive audits typically include activities such as
conducting site visits to inspect the measurement infrastructure,
verifying the meter volume calculations, and reviewing operator-
reported oil and gas production volumes. According to ERCB staff,
these substantive audits are labor intensive and can take up to 4
months to complete. Furthermore, EPAP officials told us that ERCB does
not have sufficient staffing levels to audit a representative sample
of facilities each year. To respond to the Auditor General's findings,
ERCB staff studied various approaches that would: (1) not require
significant additional operating funding; (2) lead to increased levels
of assurance over ERCB measurement and reporting requirements; and (3)
lead to increased levels of compliance through continuous improvement.
ERCB examined several alternatives, including requiring operators to
conduct sufficient self-audits, before arriving at the adopted
approach, which requires operators' senior executives to submit an
annual declaration attesting to the state of their internal controls
designed to ensure compliance with ERCB measurement and reporting
requirements. During the development of this program, ERCB held at
least 16 meetings with oil and gas operator representatives over 8
months to receive input on the EPAP design and on the wording of the
new ERCB directive. EPAP officials explained that this approach would
lead to both continuous improvement in measurement and reporting
accuracy and would not require additional ERCB operating resources.
One specific issue EPAP officials expect this approach to address is
increasing senior executive involvement with addressing measurement
and reporting issues with operators. EPAP officials told us that
operator's own production accountants or measurement specialists would
regularly identify production or measurement reporting problems, but
operators' senior executives would not take corrective actions. EPAP
officials said that requiring senior executives to sign a statement
attesting to the level of assurance over compliance with ERCB
measurement and reporting requirements, similar to the financial
requirements included in the Sarbanes-Oxley law, may lead to increased
interest from senior executives.
EPAP was to begin the implementation phase in January 2010. This phase
is scheduled to end in December 2010, according to EPAP officials. The
implementation phase provides time for operators to evaluate their
internal controls and to strengthen its controls. Beginning in 2011,
ERCB will require that all operators in Alberta submit their annual
declaration. The penalty for not submitting a declaration is to be
considered a significant noncompliance action. The initial effect of
this noncompliance is that the operator will receive more scrutiny
from the ERCB and will likely receive more action items as a result.
Failure by the operator to respond to action items that arise from
this scrutiny can result in the operator's name being published on the
ERCB Web site and, eventually, all future applications being submitted
by the operator will receive increased levels of review, significantly
slowing the approval process. According to ERCB staff, this increased
level of review and the publication of the operators' name on the ERCB
Web site will have a larger impact on an operator's operations than a
financial penalty because delays in approving applications, including
drilling permits, directly affect an operator's revenue stream.
According to ERCB officials, ERCB will track the performance of EPAP
by:
(1) tracking the number of operators who submit their annual
declarations;
(2) determining whether field inspectors find more or fewer
noncompliances at facilities;
(3) determining whether or not operator data accuracy and completeness
improve over time;
(4) determining whether the number of operator voluntary self-
disclosures increase or decrease over time; and:
(5) determining whether the number of action items increase or
decrease over time.
Many Entities Rely on Volume Balancing to Verify Production:
Verifying oil and gas volumes through volume balancing is a commonly
used practice employed by many entities, including private oil and gas
companies, foreign countries, and some state and federal entities.
Volume balancing involves totaling the volumes of oil and gas produced
from a variety of upstream meters and, then, comparing that total to
the volume measured at a downstream meter. An illustration of system
balancing is shown below (see figure 11).
Figure 11: Volume Balancing Diagram Illustrating Gas Volumes Entering
and Leaving a System:
[Refer to PDF for image: illustration]
The illustration depicts gas being routed through different channels
into the Gas Processing Plant, then to a Pipeline for delivery to
consumers.
Source: GAO.
[End of figure]
Private Companies Use Balancing to Manage Their Everyday Operations:
Many private oil and gas companies use volume balancing to manage
their everyday operations. For example, pipeline transportation
companies use oil and gas balancing routinely to help manage their
pipeline networks, enabling them to know how much gas they are
transporting at any time and giving them the ability to detect leaks
and other problems. According to officials at the pipeline companies
we spoke with, balancing can be done on a daily, hourly, or other
basis; and they are generally able to balance volumes within 1 to 2
percent. SCADA systems also assist private pipeline companies in
balancing their volumes.
Balancing also enables companies to use larger gas meters with greater
accuracy to balance the volumes of smaller gas meters with less
accuracy. According to officials at Interior and at private companies,
smaller gas meters closer to the well head are usually more likely to
have greater uncertainty because well head flow may be intermittent,
they may operate at lower pressures, or liquids may be present in the
gas stream, among other reasons. However, larger meters further
downstream of the well heads, which measure gas from several streams
at one time, are generally more accurate because flow is less
intermittent at higher pressures, and because liquids are more likely
to be separated out by separation equipment, which is more economical
to install further downstream. The greater accuracy of meters
downstream was noted by a BLM official, who told us that gas meters
closer to the well head generally measure 1 or 2 percent less gas
volume than meters downstream.
Volume Balancing Is Used for Production Verification by Foreign
Governments and Private Companies:
Foreign countries and private companies also use volume balancing to
track and verify production. Specifically, representatives we spoke
with from the United Kingdom and Canada told us that they compare
reports from local natural gas pipeline companies against reports from
the larger pipeline companies that deliver the gas to consumers.
According to officials from the Canadian province of Alberta, their
ability to access information from several different gas producers and
private pipeline transportation companies allow them to perform
balancing. A United Kingdom official told us that their Department of
Energy and Climate Change compares oil and gas balances monthly in
order to find discrepancies. The official noted that it was typical to
find that more liquid oil is measured on well head meters than in the
larger meters that gather production from several oil wells; they
noted that the opposite was true for natural gas, where offshore
meters generally measure less gas than is measured by larger meters
downstream, usually by a factor of 1 percent or less.
Interior Offshore and Some State Governments Conduct Volume Balancing
on a Limited Basis:
In the United States, Interior conducts one activity for commingled
offshore oil and gas that amounts to a limited form of volume
balancing. State government officials in three states told us that
they incorporate some balancing activities into their audits. OEMM
requires offshore producers who are commingling their production with
state oil and gas production to report their production separately in
a production allocation schedule report. This report enables OEMM to
compare the volumes that are reported by individual leases against the
total production of all leases reported by the operators. In addition,
four U.S. state governments we reviewed also perform volume balancing
during audits for commingled leases. Generally, state officials told
us that they do not perform "field-wide" balancing of oil and gas
systems on a regular basis.
[End of section]
Appendix VI: Production Verification and Accountability Practices of
Selected States as Reported by State Officials:
We reviewed the production verification practices of the 10 states
where the most oil and gas is produced on state, federal, and private
lands; we found that these states use some of the same production
verification practices as the federal government does offshore and
onshore. For example, 5 of the 10 states regularly inspected oil and
gas meters for measurement issues, but of those that do, they
generally employ fewer inspectors than the federal government.
However, states do engage in practices that the federal government
does not; for example, 5 of the states that we reviewed equipped
inspectors with electronic devices in the field; 2 of these states
also provided wireless access to these inspectors. Table 20 presents a
summary of information reported by state officials and documents
regarding their states' production verification practices.
Table 20: Summary of Production Verification Practices in 10 States as
Reported by State Officials:
Number of state agencies that oversee oil and gas measurement;
Alaska: 2;
California: 1;
Colorado: 2;
Kansas: 2;
Louisiana: 2;
New Mexico: 2;
Oklahoma: 2;
Texas: 2;
Utah: 3;
Wyoming: 3.
Point of measurement:
Policies require operators to report location of royalty meters;
Alaska: Yes;
California: No;
Colorado: No;
Kansas: a;
Louisiana: Yes;
New Mexico: No;
Oklahoma: Yes;
Texas: No;
Utah: No;
Wyoming: No.
Inspections:
Inspectors regularly inspect meters and site security;
Alaska: Yes;
California: Yes;
Colorado: Yes;
Kansas: No;
Louisiana: No;
New Mexico: No;
Oklahoma: No;
Texas: Yes;
Utah: No;
Wyoming: Yes.
Inspectors regularly witness tank gauging;
Alaska: N/A;
California: Yes;
Colorado: Yes;
Kansas: No;
Louisiana: No;
New Mexico: No;
Oklahoma: No;
Texas: Yes;
Utah: No;
Wyoming: No.
Inspectors regularly witness meter calibrations;
Alaska: Yes;
California: Yes;
Colorado: Yes;
Kansas: No;
Louisiana: No;
New Mexico: No;
Oklahoma: No;
Texas: Yes;
Utah: No;
Wyoming: No.
Inspectors regularly inspect orifice plates in gas meters;
Alaska: Yes;
California: Yes;
Colorado: Yes;
Kansas: No;
Louisiana: No;
New Mexico: No;
Oklahoma: No;
Texas: Yes;
Utah: No;
Wyoming: No.
Inspectors regularly inspect oil quality sampling (grind out);
Alaska: Yes;
California: Yes;
Colorado: Yes;
Kansas: No;
Louisiana: No;
New Mexico: No;
Oklahoma: No;
Texas: Yes;
Utah: No;
Wyoming: No.
Number of regular measurement inspectors (full-time equivalent);
Alaska: 5;
California: 1.2;
Colorado: 1;
Kansas: 0;
Louisiana: 0;
New Mexico: 0;
Oklahoma: 0;
Texas: 8;
Utah: 0;
Wyoming: 4.
Approximate number of wells or meters examined per year by State;
Alaska: 2,000;
California: 250;
Colorado: 30-40;
Kansas: [A];
Louisiana: 1-2;
New Mexico: 0;
Oklahoma: 0;
Texas: 3,000;
Utah: 200;
Wyoming: 420.
Inspectors use computer laptops or other handheld electronic devices
in the field;
Alaska: Yes;
California: No;
Colorado: No;
Kansas: Yes[B];
Louisiana: No;
New Mexico: Yes[B];
Oklahoma: No;
Texas: Yes;
Utah: No;
Wyoming: Yes.
Inspectors have wireless electronic data access in the field;
Alaska: No;
California: No;
Colorado: No;
Kansas: Yes[B];
Louisiana: No;
New Mexico: Yes[B];
Oklahoma: No;
Texas: Yes;
Utah: N/A;
Wyoming: No.
Agencies collect real-time production data of oil and gas production
or gathering;
Alaska: No;
California: No;
Colorado: No;
Kansas: No;
Louisiana: No;
New Mexico: No;
Oklahoma: No;
Texas: No;
Utah: No;
Wyoming: No.
Comparison of production reports and royalty payment records;
Alaska: Yes;
California: Yes;
Colorado: Yes;
Kansas: [A];
Louisiana: No;
New Mexico: Yes;
Oklahoma: No;
Texas: Yes;
Utah: Yes;
Wyoming: Yes.
Volume measurement standards:
Electronic flow computers referenced by regulation;
Alaska: Yes;
California: No;
Colorado: Yes;
Kansas: No;
Louisiana: No;
New Mexico: No;
Oklahoma: Yes;
Texas: No;
Utah: No;
Wyoming: No.
Most recent year of most recent API standards cited for oil meters;
Alaska: 1998;
California: 1960;
Colorado: 2005;
Kansas: N/A;
Louisiana: 2004;
New Mexico: N/A;
Oklahoma: N/A;
Texas: 2007;
Utah: N/A;
Wyoming: 2004.
Most recent year of most recent API standards cited for gas meters;
Alaska: 1998;
California: c.1950;
Colorado: 2007;
Kansas: N/A;
Louisiana: 1936;
New Mexico: N/A;
Oklahoma: 2006;
Texas: N/A;
Utah: None;
Wyoming: N/A.
Source: GAO and state regulatory officials.
[A] This information was not provided by the state officials we spoke
with.
[B] Kansas and New Mexico inspection staff do not regularly conduct
measurement inspections; however, their health and safety inspectors
use computer laptops and remote data in the field.
[End of table]
[End of section]
Appendix VII: GAO Contacts and Staff Acknowledgments:
GAO Contact:
Frank Rusco (202) 512-3841 or ruscof@gao.gov:
Staff Acknowledgments:
In addition to the contact named above, Jon Ludwigson, Assistant
Director; Lee Carroll; Melinda Cordero; Nancy Crothers; Glenn C.
Fischer; Cindy Gilbert; and Barbara Timmerman made key contributions
to this report. Also contributing to this report were Maria Vargas and
Muriel Forster.
[End of section]
Related GAO Products:
Energy Policy Act of 2005: Greater Clarity Needed to Address Concerns
with Categorical Exclusions for Oil and Gas Development under Section
390 of the Act. [hyperlink, http://www.gao.gov/products/GAO-09-872].
Washington, D.C.: September 26, 2009.
Federal Oil And Gas Management: Opportunities Exist to Improve
Oversight. [hyperlink, http://www.gao.gov/products/GAO-09-1014T].
Washington, D.C.: September 16, 2009.
Royalty-In-Kind Program: MMS Does Not Provide Reasonable Assurance It
Receives Its Share of Gas; Resulting in Millions in Forgone Revenue.
[hyperlink, http://www.gao.gov/products/GAO-09-744]. Washington, D.C.:
August 14, 2009.
Mineral Revenues: MMS Could Do More to Improve the Accuracy of Key
Data Used to Collect and Verify Oil and Gas Royalties. [hyperlink,
http://www.gao.gov/products/GAO-09-549]. Washington, D.C.: July 15,
2009.
Strategic Petroleum Reserve: Issues Regarding the Inclusion of Refined
Petroleum Products as Part of the Strategic Petroleum Reserve.
[hyperlink, http://www.gao.gov/products/GAO-09-695T]. Washington,
D.C.: May 12, 2009.
Oil and Gas Management: Federal Oil and Gas Resource Management and
Revenue Collection In Need of Stronger Oversight and Comprehensive
Reassessment. [hyperlink, http://www.gao.gov/products/GAO-09-556T].
Washington, D.C.: April 2, 2009.
Oil and Gas Leasing: Federal Oil and Gas Resource Management and
Revenue Collection in Need of Comprehensive Reassessment. [hyperlink,
http://www.gao.gov/products/GAO-09-506T]. Washington, D.C.: March 17,
2009.
Department of the Interior, Minerals Management Service: Royalty
Relief for Deepwater Outer Continental Shelf Oil and Gas Leases--
Conforming Regulations to Court Decision. [hyperlink,
http://www.gao.gov/products/GAO-09-102R]. Washington, D.C.: October
21, 2008.
Oil and Gas Leasing: Interior Could Do More to Encourage Diligent
Development. [hyperlink, http://www.gao.gov/products/GAO-09-74].
Washington, D.C.: October 3, 2008.
Oil and Gas Royalties: MMS's Oversight of Its Royalty-in-Kind Program
Can Be Improved through Additional Use of Production Verification Data
and Enhanced Reporting of Financial Benefits and Costs. [hyperlink,
http://www.gao.gov/products/GAO-08-942R]. Washington, D.C.: September
26, 2008.
Mineral Revenues: Data Management Problems and Reliance on Self-
Reported Data for Compliance Efforts Put MMS Royalty Collections at
Risk. [hyperlink, http://www.gao.gov/products/GAO-08-893R].
Washington, D.C.: September 12, 2008.
Oil and Gas Royalties: The Federal System for Collecting Oil and Gas
Revenues Needs Comprehensive Reassessment. [hyperlink,
http://www.gao.gov/products/GAO-08-691]. Washington, D.C.: September
3, 2008.
Oil and Gas Royalties: Litigation over Royalty Relief Could Cost the
Federal Government Billions of Dollars. [hyperlink,
http://www.gao.gov/products/GAO-08-792R]. Washington, D.C.: June 5,
2008.
Strategic Petroleum Reserve: Improving the Cost-Effectiveness of
Filling the Reserve. [hyperlink,
http://www.gao.gov/products/GAO-08-726T]. Washington, D.C.: April 24,
2008.
Mineral Revenues: Data Management Problems and Reliance on Self-
Reported Data for Compliance Efforts Put MMS Royalty Collections at
Risk. [hyperlink, http://www.gao.gov/products/GAO-08-560T].
Washington, D.C.: March 11, 2008.
Strategic Petroleum Reserve: Options to Improve the Cost-Effectiveness
of Filling the Reserve. [hyperlink,
http://www.gao.gov/products/GAO-08-521T]. Washington, D.C.: February
26, 2008.
Oil and Gas Royalties: A Comparison of the Share of Revenue Received
from Oil and Gas Production by the Federal Government and Other
Resource Owners. [hyperlink, http://www.gao.gov/products/GAO-07-676R].
Washington, D.C.: May 1, 2007.
Oil and Gas Royalties: Royalty Relief Will Cost the Government
Billions of Dollars but Uncertainty Over Future Energy Prices and
Production Levels Make Precise Estimates Impossible at this Time.
[hyperlink, http://www.gao.gov/products/GAO-07-590R]. Washington,
D.C.: April 12, 2007.
Royalties Collection: Ongoing Problems with Interior's Efforts to
Ensure A Fair Return for Taxpayers Require Attention. [hyperlink,
http://www.gao.gov/products/GAO-07-682T]. Washington, D.C.: March 28,
2007.
Oil and Gas Royalties: Royalty Relief Will Likely Cost the Government
Billions, but the Final Costs Have Yet to Be Determined. [hyperlink,
http://www.gao.gov/products/GAO-07-369T]. Washington, D.C.: January
18, 2007.
Strategic Petroleum Reserve: Available Oil Can Provide Significant
Benefits, but Many Factors Should Influence Future Decisions about
Fill, Use, and Expansion. [hyperlink,
http://www.gao.gov/products/GAO-06-872]. Washington, D.C.: August 24,
2006.
Royalty Revenues: Total Revenues Have Not Increased at the Same Pace
as Rising Oil and Natural Gas Prices due to Decreasing Production
Sold. [hyperlink, http://www.gao.gov/products/GAO-06-786R].
Washington, D.C.: June 21, 2006.
Oil and Gas Development: Increased Permitting Activity Has Lessened
BLM's Ability to Meet Its Environmental Protection Responsibilities.
[hyperlink, http://www.gao.gov/products/GAO-05-418]. Washington, D.C.:
June 17, 2005.
Mineral Revenues: Cost and Revenue Information Needed to Compare
Different Approaches for Collecting Federal Oil and Gas Royalties.
[hyperlink, http://www.gao.gov/products/GAO-04-448]. Washington, D.C.:
April 16, 2004.
[End of section]
Footnotes:
[1] GAO, Data Management Problems and Reliance on Self-Reported Data
for Compliance Efforts Put MMS Royalty Collections at Risk,
[hyperlink, http://www.gao.gov/products/GAO-08-893R] (Washington,
D.C.: Sept. 12, 2008).
[2] Subcommittee on Royalty Management, Royalty Policy Committee,
Report to the Royalty Policy Committee: Mineral Revenue Collection
from Federal and Indian Lands and the Outer Continental Shelf
(Washington, D.C., 2007).
[3] The Glenwood Springs, Colorado, field office relocated to Silt,
Colorado, on September 8, 2009.
[4] Representatives from the Roswell, New Mexico, BLM field office and
the Hobbs, New Mexico, BLM field station were included in our
discussion with Carlsbad, New Mexico, BLM field office staff.
[5] Pub. L. No. 66-146, 41 Stat. 437 (1920).
[6] Pub. L. No. 94-258, 90 Stat. 303 (1976).
[7] 67 Stat. 462 (1953) codified at 43 U.S.C. § 1331 et seq.
[8] Pub. L. No. 104-58, 109 Stat. 563 (1995).
[9] MMS's Minerals Revenue Management, a separate directorate from
OEMM, is responsible for collecting, accounting for, and distributing
revenues associated with offshore and onshore oil, gas, and mineral
production from leased federal and Indian lands. This directorate is
located in Lakewood, Colorado.
[10] Pub. L. No. 104-113, 110 Stat. 775 (1996). Many regulations
establish or incorporate technical standards. The National Technology
Transfer and Advancement Act requires all federal agencies and
departments to use technical standards developed or adopted by
voluntary consensus standards bodies unless the agency determines that
use of such standards is contrary to law or impractical, and provides
an explanation to the U.S. Office of Management and Budget (OMB) of
that determination. OMB must report to Congress annually on instances
in which agencies submitted such explanations for not using voluntary
consensus standards.
[11] The representative sample is spun for 5 minutes in a centrifuge
to determine the water and sediment content of the oil.
[12] Wafer V-Cone meters work similarly to orifice meters in that they
measure the differential pressure. While the manufacturer claims that
wet gas measurement is possible with these meters, this has never been
substantiated by BLM. Multiphase meters are designed to measure both
oil and gas simultaneously and are still being studied and improved by
industry. MMS has allowed the use of multiphase meters for offshore
measurement in some instances.
[13] BTU is the amount of heat energy needed to raise the temperature
of one pound of water by one degree Fahrenheit.
[14] Both types of samples are drawn by attaching a sample bottle to a
tap attached to a sample probe in the meter run and collecting a
volume of gas into a bottle designed for this purpose.
[15] Pub. L. No. 97-451, 96 Stat. 2447 (1983).
[16] 30 U.S.C. §1718(c).
[17] Upon the request of companies, BLM and OEMM can administratively
combine contiguous federal, state, or private leases into units to
more efficiently explore and develop an oil or gas reservoir and to
lessen the surface disruption caused by the building of roads and the
installation of pipelines and production equipment.
[18] In OEMM's Pacific region, discrepancies are handled within the
region, instead of by other MMS staff.
[19] BLM's regulations are implemented and supplemented by onshore oil
and gas orders which go through the rule making process and are
binding on lessees and operators. The use of the term regulations
throughout this report encompasses orders.
[20] American Petroleum Institute, Manual of Petroleum Measurement
Standards, Chapter 14--Natural Gas Fluids Measurement, Section 3--
Concentric, Square-Edged Orifice Meters, Part 2--Specification and
Installation Requirements, Fourth Edition, Washington, D.C., Apr.
2000; reaffirmed Mar. 2006.
[21] 30 C.F.R. § 250.198.
[22] 61 Fed. Reg. 60019 (Nov. 26, 1996).
[23] Subcommittee Report to the Royalty Policy Committee, Washington,
D.C., December 2007.
[24] Office of the Inspector General, U.S Department of the Interior,
Evaluation of Royalty Recommendations Made to the Department of the
Interior Fiscal Year 2006 - February 2009, (CR-EV-MOA-0003-2009,
Washington, D.C., Apr. 2009).
[25] The term variance is not used by OEMM in the Gulf of Mexico
region, but OEMM officials told us that it refers to the same process.
[26] A Coriolis meter is a type of meter that can measure fluids by
measuring the mass of a fluid traveling past a fixed point per unit
time. In this particular application, a Coriolis meter was mounted on
the back of a truck.
[27] Flow conditioners are devices placed within the upstream portion
of the meter run to both stabilize the gas flow and allow for a
shorter meter run, which is necessary for orifice meters to accurately
measure the gas.
[28] BLM, Instruction Memorandum No. 2007-022: Policy for Approving
Variances Allowing the Use of "Wafer V-Cone Meters" at Federal and
Indian Points of Measurement (Nov. 16, 2006).
[29] BLM, Instruction Memorandum No. 2009-027: The Feasibility Use of
Truck Mounted Meters for Oil Measurement Onshore (Nov. 26, 2008).
[30] 30 C.F.R. § 250.1203(e)
[31] Under current law, operators are required to have all data
associated with the meter for six years, and are required to provide
this information to Interior, regardless of who owns the meters. 30
U.S.C. §1713.
[32] Oil and gas pipelines may be subject to oversight by federal and
state entities, depending on the nature of the pipeline. Interstate
pipelines are regulated by the U.S. Department of Transportation for
safety issues, and the U.S. Federal Energy Regulatory Commission for
the transmission and sale of natural gas for resale in interstate
commerce. Intrastate pipelines, such as gathering systems located on
federal leases are, in some instances, overseen to some extent by
state regulators.
[33] Measurement points are meter locations which measure oil or gas
that are reported on the operator-reported monthly production report.
[34] A commingling request is a request made by the lease operator to
mix together oil or gas from separate leases prior to measurement.
[35] Wyoming BLM, Instruction Memorandum No. WY-2003-036: Policy
Clarification Regarding BLM's Point of Measurement (May 30, 2003).
[36] [hyperlink, http://www.gao.gov/products/GAO-08-893R].
[37] OEMM offices responsible for the outer continental shelf in the
Pacific and Alaska regions were able to inspect all measurement
locations; they have a limited number of platforms.
[38] About 980 out of the approximately 2,900 active royalty meters in
the Gulf of Mexico are found on measurement locations where more than
1,000 barrels per day of oil (or, for gas, the energy equivalent) are
produced.
[39] Record reviews are a more in-depth and manual version of what
MMS's Liquid Verification System and Gas Verification System do for
offshore oil and gas production.
[40] We did not include data from the White River, Colorado, field
office, because the Interior Office of the Inspector General is
currently evaluating the reliability of the inspection data from that
office.
[41] An OEMM official told us that for fiscal years prior to 2008,
OEMM could not precisely identify the number of meters that inspectors
were required to witness. In addition, for fiscal years prior to 2008,
the official told us that inspectors may not have recorded every meter
witnessing.
[42] In the Cobell class-action lawsuit--concerning the government's
management of Native American trust funds, a U.S. District Court
Judge, on December 5, 2001, ordered Interior to disconnect from the
internet all information technology systems that house or provide
access to individual Indian trust data. Specifically, Interior's IT
systems were impacted multiple times since 2001. According to BLM's
database manager, the shutdown dates were: (1) December 2001 through
May 2002, (2) June 2003 through September 2003, (3) March 2004, and
(4) April 2005 through October 2005 for the federal data and August
2008 for Indian data.
[43] We did not include the results of our analysis for the White
River, Colorado, field office as the Interior Office of the Inspector
General is currently evaluating the reliability of the office's
inspection data.
[44] BLM, Instruction Memorandum No. 2009-186: Policy for Verifying
Heating Value of Gas Produced From Federal and Indian Leases (July 28,
2009).
[45] Pub. L. No. 97-255, 96 Stat. 814 (1982). FMFIA was repealed as
part of the general revisions to Title 31, U.S. Code. The key
provisions of FMFIA were codified at 31 U.S.C. § 3512 (c), (d).
[46] GAO, Standards for Internal Control in the Federal Government,
[hyperlink, http://www.gao.gov/products/GAO/AIMD-00-21.3.1]
(Washington, D.C.: Nov. 1999).
[47] OEMM's Gulf of Mexico region oversees approximately 99 percent of
all offshore production, with the remaining offshore production
occurring within the Pacific and Alaska regions.
[48] [hyperlink, http://www.gao.gov/products/GAO/AIMD-00-21.3.1].
[49] [hyperlink, http://www.gao.gov/products/GAO/AIMD-00-21.3.1].
[50] Some field offices with larger numbers of petroleum engineer
technicians include supervisory petroleum engineer technician
positions, which help manage other petroleum engineer technicians and
are, in turn, evaluated by the field office managers.
[51] This nongeneralizable sample consisted of a review of 43 out of
3,556 available files to select from between fiscal years 2004 and
2008 for the four field offices we reviewed. Because we did not
conduct a random sample, our analysis does not indicate the prevalence
or extent of this problem. This applies to both the field offices
whose files we reviewed, as well as the 26 field offices whose files
we did not review.
[52] Because OEMM only retains inspection file hard copies for the two
most recent fiscal years, we were unable to review files from fiscal
years 2004-2006. This nongeneralizable sample consisted of a review of
20 out of a total of 562 available hard copy inspection files for
fiscal years 2007 and 2008 for the two OEMM district offices we
reviewed. Because our sample was not random, our analysis does not
indicate the prevalence or extent of the completeness of the files, or
the subsequent database documentation, of the OEMM district office
hard copy files we did not review. This applies to both the two
district offices whose files we reviewed, as well as the five district
offices whose files we did not review.
[53] In OEMM's Pacific region, geoscientists handle measurement
approvals.
[54] [hyperlink, http://www.gao.gov/products/GAO/AIMD-00-21.3.1].
[55] 30 U.S.C. § 1711(b)(2).
[56] The Hobbs, New Mexico, field station does not employ any
petroleum engineers.
[57] For the purposes of our analysis, we considered turnover to be
any staff person who left BLM or OEMM, relocated to another BLM field
office or OEMM district or regional office, or switched positions
within BLM or OEMM. Additionally, some of the field offices we
examined had low numbers of staff in the positions we analyzed which
results in high turnover rates when limited numbers of staff move from
their positions.
[58] Pub. L. No. 106-469, 114 Stat. 2029, 2041 (2000), codified at 42
U.S.C. § 6217.
[59] Specifically, the judge presiding over the case ordered the
shutdown of all of Interior's IT systems several times over the course
of 4 years, delaying many IT projects.
[60] The results we obtained from these discussions are not
generalizable to all BLM field offices.
[61] Our site visit to the Rawlins, Wyoming, BLM field office was a
scoping visit. We did not administer our semistructured interview
guide to staff in this office.
[62] Representatives from the Roswell, New Mexico, BLM field office
and the Hobbs, New Mexico, BLM field station were included in our
discussion with Carlsbad, New Mexico, BLM field office staff.
[63] These inspectors were not counted in Table 16 because our method
identified these staff as part of the "turnover" count for FY 2009 and
FY 2010.
[64] We interviewed state regulatory officials and reviewed oil and
gas measurement regulations for: Alaska, California, Colorado, Kansas,
Louisiana, New Mexico, Oklahoma, Texas, Utah, and Wyoming.
[65] RMDMS is software created by the Ground Water Protection Research
Foundation, with assistance from the Department of Energy. RBDMS is
now used by 20 states and is intended to help state agencies to
improve regulatory decision making, make oil and gas information more
readily available to industry, increase environmental compliance, and
reduce the regulatory barriers to oil and gas production.
[66] The address of the Wyoming Oil and Gas Conservation Commission
Web site is [hyperlink, http://wogcc.state.wy.us].
[End of section]
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