&EPA
United States
Environmental Protection
Agency
Air and Radiation
6202J
EPA-430-N-OI-004
Summer 200 I
ATURAL GAS STAR
Summer 200 I
I I
<
r
Identification and Evaluation of Opportunities To
Reduce Methane Losses at Four Processing Plants
Recent findings reveal that significant
opportunities exist for cost-effectively reducing
natural gas losses at gas processing plants through
the control of leaking equipment components
and leakage of process gas into vent and flare
systems. The study, led by the Gas Technology
Institute (GTI, formerly the Gas Research
Institute) in cooperation with EPA's Natural Gas
STAR Program and industry participants, was
conducted in late 2000 at four gas processing
facilities that varied in terms of age, types, and
throughputs. The selected facilities were
expected to offer a range of opportunities for
cost-effective reduction of natural gas losses.
Directed inspection and maintenance at gas
processing plants is among several best
management practices and partner reported
opportunities recommended by the Gas STAR
Program for reducing methane emissions. The
objective of the study was to demonstrate with
actual field data that a comprehensive leak
detection and repair program could reduce gas
losses while enhancing profits. GTI's Hi-Flow™
Sampler technology was used to gather data on
emissions from continuous vents, combustion
equipment, and flare systems. Assessment of the
emissions data coupled with diagnostic checks of
natural gas-fueled equipment provided an
opportunity to examine whether reductions in
methane gas emissions could be achieved
sensibly, could be verified, and could create an
economic opportunity for the industry.
Most leak detection and repair programs in the
natural gas industry rely on EPA's Method 21,
which measures the concentration of methane
leaked into the air and then uses a correlation
equation to estimate the leak rate. In con-
ventional leak programs, Method 21 is used to
screen the facility at a prescribed frequency such
as annually or quarterly. Based on the method's
specifications, all components that produce
screening values greater than 10,000 parts per
million (ppm) are required to be repaired.
Because the Method 21 equations are applicable
only between 10,000 and 100,000 ppm, any leak
that screens beyond this upper concentration
results in the same estimated leak rate. In
contrast, the methodology employed by GTI in
this and other studies differs from Method 21 in
that a special device (the Hi-Flow™ Sampler) is
used to measure the actual leak rate by volume.
These volumetric measurements can then be
used as reliable data in a cost-benefit analysis to
decide which leaks are cost-effective to repair.
IN THIS ISSUE
Program Tools 3
The Natural Gas STAR Program is developing three new
tools (Online Analytic Tool, Online Reporting Tool, and
Emission Reduction Tracking and Data Collection Tool)
that will be available this fall.
Partner Experiences 4
Natural Gas STAR partners share their experiences in
implementing methane emission reduction technologies
and practices in two new Lessons Learned.
In the Spotlight 6
The Natural Gas STAR Program provides partners with
case studies that show how companies reduced emissions
and saved money by joining the Natural Gas STAR Program,
and partner reported opportunities (PRO) fact sheets that
describe processes and technologies reported by partners
as ''other Best Management Practices" in their annual
reports.
Workshop Registration Form 11
The 8th Annual Natural Gas STAR Workshop will be held
on October 23-25, 2001. Register now! Workshop details
are provided on page 4.
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Gas-Plant Tests
continued from page I
Data from GTI studies show that only about 10
percent of the fugitive emissions that screen above the
10,000-ppm threshold are cost effective to repair. This
is due to the fact that leaks with a high concentration
reading may actually have a low leak rate. Therefore
the gas savings alone may not justify high repair costs.
On the other hand, 20 percent of the components that
screen at values less than 10,000 ppm are cost
effective to repair, but would not be repaired based on
the Method 21 criteria. GTI's method relies on cost-
efficient leak detection techniques and on its
Hi-Flow™ Sampler—a leak measurement device—
which accurately measures leak volume. This method
significantly reduces the cost of leak programs at
natural gas facilities. Their data have shown that
implementing this procedure at natural gas compressor
stations can reduce emissions by 80 to 90 percent with
a payback period of 6 to 12 months. They have also
shown that 10 percent of the leaks are responsible for
80 to 90 percent of the emissions, and thus, significant
reductions can be achieved by repairing a relatively
small number of leaks.
The intensive fugitive-component and screening-
measurement program conducted by GTI targeted
facilities that process sweet and sour gas and use
compression, separation, stabilizing, deep cryogenic
recovery and rejection, mole sieve and triethylene and
diethylene glycol dehydration, and other gas-refining
Table 1 Summary of Surveyed Plants
Plant No.
I
2
3
4
Type
sweet
sweet
sweet
sour
Age
35
50
20
35
Throughput
(mmscfd)
54
60
2IO
1 20
Number of
Components
16,050
14,424
56,463
14,168
techniques. The four plants had been operating from
20 to 50 years. Table 1 provides the type, age,
throughputs (mmscfd), and the number of
components for the four plants. The survey at each
facility included screening to detect leaks; measuring
emission rates from leakers and from continuous flows
and emergency vents during passive periods; counting
surveyed equipment components; measuring residual
gas flare rates; testing natural gas-fueled combustion
equipment; sampling process and waste streams;
developing an emissions inventory; determining site-
specific average emission factors for fugitive leaks; and
preparing cost-benefit analyses to identify control
opportunities.
Equipment components on all process, fuel, and waste
gas systems were screened for leaks. Surveyed
components included flanged and threaded
connections, valves, pressure relief devices, open-
ended lines, blowdown vents, instrument fittings,
regulator and actuator diaphragms, compressor seals,
compressor crankcase vents, engine crankcase vents,
sewer drains, and sump and drain tank vents. Leak
detection was conducted with bubble tests using soap
solution, portable hydrocarbon gas detectors, and an
ultrasonic leak detector. Bubble tests were performed
on most components because that is the most rapid
screening test. Values greater than 10,000 ppm were
considered to be leaks. Leaking components were
tagged; the specific source and date were noted; and
measurements were taken.
The Hi-Flow™ Sampler was the primary method
used to determine emission rates. This device was
developed by GTI as an economic means of
measuring the emission rate from leaking components
with sufficient accuracy to allow an objective cost-
benefit analysis of each repair opportunity. Relative to
the two-orders-of-magnitude error rates (plus or
minus) of the Method 21 correlation equations, the
continued on page 9
Natural Gas STAR Partner Update • Summer 2001
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PROG RAM
New Natural Gas STAR Tools
The Natural Gas STAR Program is developing three new Web-based tools that will allow companies to analyze benefits of the
Best Management Practices (BMPs) and Partner Reported Opportunities (PROs); enable partners to submit their annual
reports online; and facilitate the emissions reduction tracking process for partner companies. These tools are expected to be
available on the Natural Gas STAR Web site in the fall of 2001.
Analyze and Evaluate BMPs and PROs
The Online Analytic Tool will allow companies to perform
economic evaluations of the Program's BMPs and PROs and
estimate potential gas savings. Users will be able to do a
customized site-specific or company-wide evaluation of
selected BMPs and/or PROs that they may be interested in
implementing. These evaluations can then be used in the
decision making process to determine the optimal level of
implementation of a specific BMP or PRO.
For each BMP or PRO that is being selected, users will be
prompted to enter operational information and economic
parameters, such as capital cost, operating costs, and
current gas price. Where available, the user will be able to
select default values for both economic and operational
inputs. Using this information, the tool will perform an
economic analysis for the selected BMP or PRO, providing
details on the total cost, return on investment, payback
period, and net present value.
Annual Reporting on the Web
The Online Reporting Tool will provide yet another option for
partners to submit their annual reports. This Web-based tool
will guide the user through the reporting process, making
annual reporting even easier than before. The tool will
prompt users to enter company-specific emission reduction
data and then perform various calculations, such as total
emission reductions
and the value of the www • epa. gov/gasstar
gas saved. Online
reporting will be password protected to ensure security of all
information. Partners will be able to return to partially
completed reports and finish them as time allows. Once the
report is complete, partners will be able to print the final form
and also submit the report to the Natural Gas STAR Program
at the click of a button. Partners who choose not to use the
Online Reporting Tool will still have the option of filling out
the form by hand, filling out the standard form in MS Word,
or using their own reporting format.
Collect and Track Company Data from the Field ••••• ••
In response to requests from partner companies, the Natural Gas STAR Program is developing an
emission reduction tracking and data collection tool. This tool will enable implementation managers
with a simple Web-based mechanism to collect information from different facilities across their
companies, aggregate these data, analyze the results, and generate and submit an annual report. The
tool will allow individuals from different facilities across the company to record project-level emission
reduction information. All data entry can be done at the facility level via the Internet. This password-
protected system will allow the implementation manager to run summary reports of the company's
emission reduction activity, including summaries of individual practices as well as company-wide
activities. Reports can be shared internally or submitted to the Natural Gas STAR Program as part of the
annual reporting process.
Natural Gas STAR Partner Update • Summer 2001
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N ER
PERI EN
Lessons Learned from GAS STAR Partners
Lessons Learned Summaries serve as effective guides for implementing Best Management Practices
(BMPs) and Partner Reported Opportunities (PROs). In these summaries, Natural Gas STAR partners
share their experiences in implementing methane emission reduction technologies and practices.
Cost/benefit information, helpful implementation tips, and reference sources are provided. Twelve
Lessons Learned Summaries are currently available on the Natural Gas STAR Web site, under Technical
Support Documents. The following are synopses of the two most recently released Lessons Learned
Summaries.
Convert Gas Pneumatic Controls to Instrument Air
Pneumatic instrument systems powered by high-pressure
natural gas are used across the natural gas industry for
process control. Typical process control applications include
pressure, temperature, liquid level, and flow rate regulation.
The constant bleed of natural gas from these controllers is
collectively one of the largest sources of methane emissions
in the natural gas industry, estimated at approximately 24
billion cubic feet (Bcf) per year from the production sector,
16 Bcf from the processing sector, and 14 Bcf per year from
the transmission sector.
Natural Gas STAR Workshop
Join us at the 8th Annual Natural Gas STAR
Implementation Workshop October 23-25, 2001 in
Houston. During the workshop, EPA will provide an
overview of the program's accomplishments, introduce
new tools, and present awards to outstanding partners.
Participants will exchange ideas on research and
emission-reduction successes during round tables and in
small sector-oriented discussions. EPA Administrator
Christine Todd Whitman has been invited to give a
keynote address and to present this year's awards, and
Mr. Arthur E. Smith Jr., VP of Environmental Health &
Safety and Environmental Counsel for NiSource
Corporation will give the industry keynote address. A
registration form is provided on page 11 of this update.
We look forward to seeing you there!
Companies can achieve significant cost savings and methane
emission reductions by converting natural gas-powered
pneumatic control systems to compressed instrument air
systems. Instrument air systems substitute compressed air for
the pressurized natural gas, eliminating methane emissions
and providing additional safety benefits. Cost-effective
applications, however, are limited to those field sites with
available electrical power, either from a utility or self-
generated source. Instrument air conversion is most
economical when a large number of pneumatic devices are
consolidated in a relatively small area.
Natural Gas STAR Partners have reported savings of up to
70 million cubic feet (Mmcf) per year per facility by
replacing natural gas-powered pneumatic systems with
instrument air systems. This represents annual savings of up
to $210,000 per facility. Partners have found that most
investments to convert pneumatic systems pay for
themselves in just over one year. Individual savings will vary,
depending on design, condition, and specific operating
conditions of the controllers. Per year, individual companies
have recovered an average of 20 Mmcf of methane
gas worth $60,000, while their costs of implementation
averaged $50,000. The value of gas saved is based on the
assumption that methane gas is worth $3.00 per thousand
cubic feet (Mcf). The implementation costs include the cost
of installing a compressor, dryer, and other accessories, as
well as the cost of annual electricity requirements.
Natural Gas STAR Partner Update • Summer 2001
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Using Hot Taps for In Service Repair
Natural gas transmission and distribution
companies often need to make new connections
between pipelines to expand or modify their
existing system. Historically, this has necessitated
shutting down a portion of the system and
purging the gas to the atmosphere to ensure a
safe connection. This procedure, referred to as a
shutdown interconnect, results in methane
emissions, loss of product and sales, customer
inconvenience, and costs associated with
evacuating the existing piping system.
Hot tapping is an alternative procedure that
makes a new pipeline connection while the
pipeline remains in service. The hot tap
procedure involves attaching a branch
connection and valve on the outside of an
operating pipeline, and then cutting out the
pipeline wall within the branch and removing the
wall section through the valve. Hot tapping
avoids product loss, eliminates methane
emissions, and prevents disruption of service to
customers.
While hot tapping is not a new practice, recent
design improvements have reduced the
complications and uncertainty that operators may
have experienced in the past. Several Natural
Gas STAR transmission and distribution partners
report using hot tap procedures regularly—small
jobs are performed almost daily while larger taps
(greater than 12 inches) are made two or three
times per year.
By performing hot taps, Natural Gas STAR
Partners have achieved methane emission
reductions and increased revenues, while
avoiding transmission and distribution service
interruptions. Gas savings are generally sufficient
to justify making all new connections to operating
lines by hot tapping. Per year, individual
companies have recovered 24,440 Mcf of
methane gas worth $80,160, while their costs
averaged $79,200 the first year, and $43,000 the
foil owing years. The average payback is 12
months. Savings include $3.00 per Mcf of gas
saved and other expenditures avoided when
operators use hot taps instead of shutdowns. The
costs included capital costs and other costs (e.g.,
O&M and contract services cost).
New Gas STAR Partners
Natural Gas STAR is pleased to welcome new partners North
Carolina Natural Gas and Columbia Natural Resources.
NCNG
A Progress Energy Company
Natural
Resources,
North Carolina Natural Gas Company
(NCNG) is based in Fayetteville, North
Carolina and is a subsidiary of Progress
Energy. NCNG provides natural gas services to 1 73,000 customers
in southcentral and eastern North Carolina. The company's primary
business is the sale and transportation of natural gas to residential,
commercial, and industrial customers located in 86 towns and cities
and on four municipal gas distribution systems. Visit NCNG's Web
site atwww.ncng.com.
Columbia Natural Resources (CNR),
headquartered in Charleston, WV, is the
exploration, production, and gathering
company of NiSource Inc. CNR is one of the
largest producers of natural gas and oil in the Appalachian Basin,
with more than three million net acreage holdings, a reserve base of
one trillion cubic feet equivalent and nearly 8,500 natural gas and
oil wells located in nine states and two Canadian provinces. As an
ISO-certified company, CNR is committed to an environmental,
health, and safety management system of the highest standard. "We
are proud to join EPA's Natural Gas STAR program," said Jim
Abcouwer, President and CEO of Columbia Natural Resources. "This
gives us a formal mechanism to continue the progress we have
made over the last decade in reducing methane emissions. It is also
a great match to our environmental management system, which sets
forth a goal of continual improvement." For more information,
contact CNR at (304) 353-5000. Information about NiSource Inc.
can be found atwww.nisource.com.
Natural Gas STAR Partner Update • Summer 2001
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Natural GAS STAR Case Studies
The Natural Gas STAR Program is continuing its series of case studies focusing on the mechanisms that partner companies
have used to successfully promote and implement a profitable methane emission reduction program. These case studies
provide insights as to how companies effectively overcome administrative and organizational barriers to joining and
implementing the program. The following are short summaries of the most recent case studies highlighting the implementation
efforts of Kerr-McGee Corporation, Columbia Gas and Gulf Transmission, and Unocal Gulf Region USA. The complete versions
of these and other case studies (Keyspan, El Paso Natural Gas, and Texaco Exploration and Production, Inc.) are available on
the Natural Gas STAR Web site, under Technical Support Documents (http://www.epa.gov/gasstar/case_studies.htm).
Kerr-McGee Corporation
Kerr-McGee Corporation, based
___ . in Oklahoma City, Oklahoma, is one of
the largest U.S.-based independent oil
and gas exploration and production
companies. Kerr-McGee operates key facilities onshore in
the United States, in the Gulf of Mexico, and in the United
Kingdom sector of the North Sea. In 2000, the company's
natural gas sales averaged 531 Mmcf.
Kerr-McGee joined the Natural Gas STAR Program in
September 1996. The company's operations and
environmental staff developed an implementation plan to
focus the company's Gas STAR efforts. The plan included
(1) identifying program best management practices (BMPs)
that the company could integrate into all new facilities
where practicable; (2) evaluating the usefulness of the
BMPs and partner reported opportunities (PROs) at older
facilities; and (3) conducting inventories of existing facilities
to determine and document past methane emission
reduction activities.
Since 1992, Kerr-McGee has reduced methane emissions by
more than 10.8 billion cubic feet (Bcf), of which over 6 Bcf
were identified from an inventory of prior reductions. This
inventory was instrumental in helping them understand and
improve efficiency at newly acquired properties. At the
2000 Annual Gas STAR Workshop, EPA honored Kerr-
McGee as the Gas STAR Production Partner of the Year in
recognition of its methane emission reduction
accomplishments. Kerr-McGee attributes its success with
Gas STAR to these main principles: building alliances among
environmental, health, and safety staff, as well as operations,
construction, and maintenance divisions; maintaining open
communications to ensure program awareness throughout
the company; and involving field personnel to keep them
informed on the issues and the importance of their efforts to
the success of the environmental programs.
Columbia Gas and Columbia Gulf Transmission
GolumrJia Gas
Transmission
Formerly subsidiaries of Columbia
Energy Group, Columbia Gas
Transmission and Columbia Gulf
Transmission are now part of NiSource Inc. NiSource is a
holding company with headquarters in Merrillville, Indiana,
Columbia Gulf
Transmission
the natural gas business from
exploration and production to
transmission, storage, and distribution,
as well as electricity generation, transmission, and distribution.
NiSource companies serve a high-growth energy corridor from
whose operating companies engage in virtually all phases of the Gulf of Mexico to the Midwest to New England.
Natural Gas STAR Partner Update • Summer 2001
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Before joining the Natural Gas STAR Program, Columbia Gulf
Transmission and Columbia Gas Transmission created a Natural
Gas STAR Steering Team, composed of representatives from all
levels of the company. The Team considered the costs of
implementing the program, the level of participation to which
the pipelines could commit, and whether the partnership could
have a positive environmental impact.
Columbia Gulf Transmission and Columbia Gas Transmission
joined the Natural Gas STAR Program in 1999. The Steering
Team began contacting field managers and technicians to assess
and catalog methane emission reduction opportunities
company-wide. The Steering Team worked with Columbia's
Environmental Excellence Program, which "promotes best
practices and innovative ideas that protect the environment
and bring benefit to the company." The Environmental
Excellence Program, created in 1996, has saved more than
$7.1 million and generated more than 100 new ideas.
Columbia attributes its success to four key elements of the
Gas STAR implementation plan:
• Integrating the Gas STAR program into existing practices
and programs promotes participation and gives Gas STAR
instant credibility.
• Creating a leadership team composed of employees from
all levels and all divisions ensures company-wide buy-in.
• Carefully considering up front the program's ultimate
goals and how it fits into the existing corporate structure.
• Setting goals and objectives, measuring them, and
following through to maintain and increase momentum
are essential.
Unocal Gulf Region USA
Unocal Gulf
Region USA,
formerly Spirit Energy, is an exploration
and production unit of Unocal
Corporation. It focuses on oil and gas
resources in the Gulf of Mexico and
onshore in Texas, Louisiana, and Alabama.
Unocal Gulf Region operates more than
200 offshore platforms and about 1,500
active wells in numerous onshore and
offshore fields. In 1999, Unocal Gulf
Region's net gas production was 747 Mmcf
per day, and net crude oil production
reached 40,000 barrels per clay.
Unocal Gulf Region had already
implemented several best management
practices before it joined the Natural Gas
STAR Program in 1998. These activities
included: installation of flash tank
separators on glycol dehydrators;
replacement of high-bleed pneumatic
devices; use of compressed air, rather
than natural gas, in instrument systems;
installation of vapor recovery units;
installation of flare systems, consolidation
of production tank batteries; and
performance of fugitive emission tests.
From 1991 to 1999, Unocal Gulf
Region recovered 640 Mmcf of
methane emissions, worth $1.9 million.
When Unocal Gulf Region joined the
Natural Gas STAR Program, the
company began promoting the Natural
Gas STAR partnership internally by
sending its employees reports on the
company's successes in reducing
methane emissions and by encouraging
them to think about other methane
reduction opportunities. Unocal Gulf
Region attributes its success with the
Natural Gas STAR Program to four key
fundamentals:
• Stress revenue gains: Many
companies do not realize that
reducing methane emissions saves
money.
• Gain management support: This
is important for implementing
voluntary programs because it adds
significance to the program and
ensures employee cooperation.
• Share results: Sharing success stories
encourages teamwork and enthusiasm
company-wide.
• Form a team: It is often easier to
achieve good results when employees
work together on targeted issues.
Unocal Gulf Region also attributes its
success to the implementation of pilot
projects to test new methane emission
reduction activities. The company
conducts a four-step analysis to evaluate
the cost-effectiveness of pilot projects.
The steps are (1) establishing the
technical feasibility, (2) estimating capital
costs, (3) estimating potential savings,
and (4) evaluating the economics of the
project. Pilot projects allow the company
to establish which practices will be the
most cost effective to incorporate on a
larger scale (i.e., corporate wide). These
projects also help determine associated
costs and savings, timeframes, staffing,
and operational requirements before
the company invests in large-scale
improvements.
Natural Gas STAR Partner Update • Summer 2001
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Partner Reported Opportunities
The Natural Gas STAR Program
encourages partners to identify,
implement, and report on the
additional activities they have
undertaken to reduce methane
emissions that are outside the
program's core set of Best
Management Practices (BMPs).
Many of these activities, referred to
as Partner Reported Opportunities
(PROs), have been summarized in
one-page fact sheets and are available
on the Natural Gas STAR Web site
under Technical Support Documents.
To date, over 40 PRO Fact Sheets are
available, with additional fact sheets in
development. Recently, the PRO Fact
Sheets were improved and updated
with more detailed economic and
operational information.
Partners can use the PRO Fact Sheets
as a guide when analyzing additional
options for reducing methane
emissions cost-effectively and
improving operational efficiency.
The new fact sheets are organized
by emission source (e.g. compressors/
engines, pipelines, wells) and by
industry sector, and they provide
detailed information in three major
areas. The first section describes the
PRO, giving details on cost,
economics, and any special operating
conditions. The second section
explains how the methane reductions
are achieved and gives information on
the potential methane emission
reductions available by implementing
the PRO. The third section presents an
economic analysis of the PRO,
including information on costs and
any additional benefits of the PRO,
such as reduced maintenance or
increased operational efficiency.
The following 10 PROs are the most
recent fact sheet additions and are now
available on the Gas STAR Web site.
• Insert Gas Main Flexible Liners.
Pulling flexible plastic piping through
leaking cast iron and unprotected steel
lines prevents underground lines from
leaking and can save 225 Mcf of
methane gas annually, per mile of
leaking pipeline.
• Isolation Valves by Design.
Designing a compressor station so that
isolation valves are placed to minimize
venting by reducing the length of gas-
filled piping can save 130 Mcf of
methane gas per year, based on 2
isolation valves positioned to exclude
1,000 feet of 24" pipeline at 600 psia.
• Install Excess Flow Valves. Excess
flow valves activate upon detection of
high-pressure drops (due to a ruptured
or severed pipeline) to shut off gas
flow in the line, saving about 16 Mcf
of methane gas per year, based on 1
activation per 350 valves in a 1/2" 50
psig service line.
• Move Fire Gates In at Compressor
Stations. Moving fire gate valves
closer to compressor stations reduces
emergency gas venting and can save
1,700 Mcf of methane gas per station
per year, based on fire gate valves
positioned to avoid blow down of
2,000 feet of 24" pipeline at 900 psia.
• Install Evactor. Evactors transfer gas
to adjacent, operating pipelines during
pipeline outages, saving 700 Mcf of
methane gas per year, based on 2
miles of 18" pipeline reduced from
600 to 50 psig through bleeder vents.
• Replace Glycol Dehydrators with
Separator/In-line Heater/Dehydrator.
Cyclone separators and in-line heaters
or dehydrators reduce methane gas
venting from glycol processing
operations and can save 130 Mcf of
methane gas per dehydrator per
year, based on dehydrating 10
MMcf/day of gas to a level of 4-7 Ibs
of water per MMcf.
• Require Improvements in Gas
Quality. Revising gas processing
and compression agreements with
producers to require reduced levels
of contaminants can reduce line
cleanings and, therefore, gas vented
during maintenance operations and
can save up to 50 Mcf of methane
gas per year, based on 16 fewer
filtration unit blow downs per year
at 600 psia.
• Main/Unit Valves Closed. Closing
main and unit valves prior to blow
down prevents venting of gas
between the main and unit valves,
saving 4,500 Mcf of methane gas
per year, based on excluding 1 mile
of 24" pipeline at 900 psia 4 times
per year.
• Clock Spring Repair. The use of
clock spring repair to repair pipeline
leaks eliminates gas venting and
allows for continuous operation of
the pipeline. This practice can save
5,400 Mcf of methane gas per year,
based on repairing a 10-foot section
of a 10-mile 20" pipeline at 800 psi.
(although partners have reported
savings up to 27,500 Mcf per
application).
• Install Velocity Tubing Strings.
Replacing existing tubing with
smaller diameter, high-velocity
tubing prevents venting during well
unloading and can save 4,680 Mcf
of methane gas per well per year,
based on one well blown to the
atmosphere bi-weekly.
"Cost and benefits will vary based on
site circumstances.
Natural Gas STAR Partner Update • Summer 2001
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Gas-Plant Tests
continued from page 2
Sampler yields more accurate data—with an error
range of 10 to 1 5 percent. Its operating principle is
based on a variable-rate, induced-flow sampling
system that captures the emissions from a leaking
component. Special attachments ensure total
emissions capture and help prevent interferences from
nearby sources. A dual-element hydrocarbon detector
directly inserted into the main sample line measures
hydrocarbon concentrations ranging from 0.01 to 100
percent. Background measurements allow the samples
to be corrected for ambient gas concentrations. A
thermal anemometer monitors the mass flow rate of
the sampled air-hydrocarbon gas mixture.
Emission rates from open-ended lines and vents were
measured with a precision rotary meter, diaphragm
flow meter, or rotameter, depending on the flow rate.
In some cases, flows were determined by measuring
the velocity profile across the vent line and flow area
at that point, using a pitot tube, hot-wire anemometer,
or thermal dispersion anemometer. Screening at open-
ended lines and vents was conducted with a
hydrocarbon sensor.
Flows in flare lines were determined by one of two
methods—measuring the velocity profile and flow
area in the line, or back-calculating based on pressure
drops between the flare tip and an upstream point on
the flare line. A portable combustible-gas detector or a
detailed lab analysis of the flare gas determined the
hydrocarbon concentration.
Performance testing involved testing each natural gas-
fueled engine and process heater or boiler to identify
avoidable inefficiencies resulting in excessive fuel
consumption and emissions. The focus was on
identifying situations in which equipment needed
tuning or repairs, or was mismatched for the current
process demands. Testing involved analyzing the flue
gas, measuring the flue gas temperature, obtaining an
analysis of the fuel gas composition, and where
possible, measuring the flow rate of the fuel gas,
combustion air, or flue gas.
Average emission factors were determined for each
type of equipment component in service at the
surveyed sites. These factors were calculated by
dividing the total emissions from all tested components
by the total number of components of that type.
Emissions from non-leaking components were based on
values taken from the literature. There were some
discrepancies between the counts in this study and
those provided by the facilities, resulting in emission
factors that are generally higher than those published in
EPA's protocol for estimating equipment leak emissions.
Total natural gas losses at the four plants are
approximately 501 Mmcf per year, worth $2,225,590
per year (based on $4.50 per Mcf, the long-term
contract price for natural gas at the time the study was
completed). Figure 1 shows the relative distribution of
natural gas losses at the case study sites by source
category. The losses include direct leakage or venting of
natural gas to the atmosphere and losses in the process
that yield no benefit. Leaking equipment components
and leakage into flare systems are the major sources of
natural gas losses at the plants. Open-ended lines
continued on page 10
Fig. 1 Distribution of Natural Gas Losses
by Emissions Source
Natural Gas STAR Partner Update • Summer 2001
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Gas-Plant Tests
continued from page 9
contribute most of the emissions from equipment leaks, although valves, connectors, and compressor
seals are also important sources as shown in Figure 2.
Fig. 2 Emissions from Fugitive
Equipment Leaks
Control vitlvfi —
2.58%
Slowdowns 0.53%
Pressure regulators 0.25%
Pump seals 1.1 TO —
-Orficc meters 0.05%
Other flow meters 0.12%
Pressure relief valves 2.22%
Fig. 3 Methane Emissions from
Economically Repairable Sources
10000
9000
8000
7000
600°
5000
4000
3000
2000
1000
n
I Total emissions
| Repairable sources
49.9*
Site No.1 Site No.2 Site No.3 Site No.4 Overall
Gas plants
Practical opportunities for reducing emissions from fugitive equipment leaks and process venting were
identified and assessed on a source-by-source basis. The sources with the greatest emissions were not
necessarily the most economical to repair or replace. About three-quarters of the identified natural gas
losses at the surveyed gas plants were economical to avoid or recover, based on preliminary estimates
of repair costs, as presented in Figure 3. Once leaks are repaired, however, they are assumed to leak
again at some point. The mean time between failures depends on the type, style, and quality of the
component; the demands of the specific application; component activity levels (number of valve
operations); and maintenance practices at the site. In a formal leak detection and repair program, mean
times between failures are tracked continuously and used to identify problem service applications and
to evaluate the potential need for changes to component specifications and maintenance practices.
"Identification and Evaluation of Opportunities To Reduce Methane Losses at Four Processing Plants," a Draft Report from the Gas
Technology Institute and Clearstone Engineering, May 25, 2001.
For more information, contact Jeff Panek at GTI, 847-768-0884, or Carrie Henderson at EPA, 202-564-23 18. Copies of the study
report will be made available when finalized.
Natural Gas STAR Partner Update • Summer 2001
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;TH A
Annual Natural Gas STAR Implementation Workshop ^ ip A
October 23-25, 2001 °*POILUT10N PREVENTER
Crowne Plaza Medical Center
Houston, Texas
Please mail or fax your completed
registration form to:
Attn: Natural Gas STAR Workshop
Eastern Research Group, Inc.
110 Hartwell Avenue
Lexington, MA 02421-3136
FAX: 781 674-2906
Please check one:
G Workshop Fees: $100/person
(includes all workshop functions
and awards luncheon)
G Awards Luncheon only: $35/person
(no admittance to technical sessions)
If no box is checked, ERG will assume
workshop registration.
Make checks payable to:
Eastern Research Group (ERG)
Overnight Accommodations
A block of rooms has been reserved at
the Houston Crowne Plaza Medical
Center for workshop participants. The
group room rate is $73/night plus 17%
tax for single or double occupancy. To
make reservations, please contact the
hotel directly at (713) 797-1110 and ref-
erence the "Natural Gas STAR
Workshop" room block. To receive this
discounted rate, you must make your
reservation no later than Tuesday,
October 9, 2001. After this date, reser-
vations will be accepted on a space and
rate available basis only.
Registration
Name.
Nickname/First name for badge
Title
Company
Company Address _
City
State
Zip
Work Phone
E-mail
Work Fax
Check the corresponding natural gas industry sector you represent:
G Production Q Gathering and Processing
Q Transmission G Distribution
Please indicate your participation in the following Natural Gas
STAR workshop functions:
G Yes G No Will you be attending the evening reception on
Tuesday, October 23?
G Yes G No Will you be attending the awards luncheon on
Wednesday, October 24?
Special dietary needs
To pay with credit card, please complete the following
information and sign the bottom:
Check one: G Visa G MasterCard G American Express
Name as it appears on credit card:
Account Number:
Expiration Date _
Amount Charged $_
Authorized Signature
**Your billing statement will show a charge from "ERG Conference
Registration Fee".
Questions about the Natural Gas STAR Workshop?
Call 888 249-8883.
Natural Gas STAR Partner Update • Summer 2001
-------
DOCUMEN
REQUEST
Name & Title:
Organization:
E-Mail Address:
Telephone #:
Date Requested:
Date Info Needed:
FAX#:
FedEx/UPS # (if info needed asap):
EPA POLLUTION PREVENTER
Please fax to
your STAR Service
Representative at
703-841-1440
or directly to the
Natural Gas
STAR Program at
202-565-2079.
PLEASE INDICT AT E W MICH
MATERIALS YOU WOULD
LIKE TO RECEIVE:
LESSONS LEARNED
1
Directed Inspection and Maintenance at Compressor Stations
2. Directed Inspection and Maintenance at Gate Stations and Surface Facilities
3. Options for Reducing Methane Emissions from Pneumatic Devices in the Natural Gas Industry
4. Installation of Flash Tank Separators
5. Reducing Methane Emissions from Compressor Rod Packing Systems
6. Reducing Emissions When Taking Compressors Off-line
7. Installing Vapor Recovery Units on Crude Oil Storage Tanks
8. Replacing Wet Seals with Dry Seals in Centrifugal Compressors
9. Reducing the Glycol Circulation Rates in Dehydrators
10. Replacing Gas-Assisted Glycol Pumps with Electric Pumps
11. Installing Plunger Lift Systems in Gas Wells
12. Using Pipeline Pump-Down Techniques To Lower Pipeline Pressure Before Maintenance
13. Convert Gas Pneumatic Controls to Instrument Air
14. Using Hot Taps for In Service Repair
STAR IMPLEMENTATION TOOLS
Video-Production
Video-Transmission/Distribution
Case Study-El Paso Natural Gas
Case Study-Brooklyn Union/Keyspan Energy
Case Study-Texaco Exploration and
Production, Inc.
Case Study-Columbia Gas and Columbia Gulf
Transmission
Case Study-Kerr-McGee Corporation
Case Study-Unocal Gulf Region USA
OUTREACH MATERIALS
Natural Gas STAR Program Brochure
Natural Gas STAR Marketing Package
Natural Gas STAR Communications
Toolkit
STAR Partner Update, Summer 1998
STAR Partner Update, Spring 1999
STAR Partner Update, Winter 1999
STAR Partner Update, Fall 2000
STAR Partner Update, Winter 2001
Most of these materials are available on the Internet at www.epa.gov/gasstar
Natural Gas STAR Partner Update • Summer 2001
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