PARTNER
UPDATE


Spring 2009 

Prospective
Projects
Spotlight



Potential
New
Opportunity:
Seal
Oil



Degassing
Vent
Recovery
and
Use



Older centrifugal compressor 

designs that use “wet” seals 

with seal oil are still used 

prevalently and can release a large 

quantity of methane to the atmosphere 

from their seal oil systems. Though 

cost­effective solutions currently exist, 

such as retrofitting to dry seals, a 

significant capital investment is 

typically required. The Natural Gas 

STAR Program recently learned of a 

The
Partner
Update
typically
addresses
project


ideas
that
have
been
reported
to
the
Natural


Gas
STAR
Program.
Occasionally
the
Program


hears
about
methane
emissions
reduction


activities
that
are
technically
feasible
but
have


not
yet
been
reported.
This
new
column
highlights
these
opportunities
and
seeks
feedback


from
Partners
on
this
and
other
potential
ideas.


new project idea with strong potential 

to reduce emissions from this significant 

Continued on page 5 H H H 

In
This
Issue:


New
Projects
Spotlight................................1


Partner
Profile.............................................1


Annual
Reporting
........................................2


University
of
Texas
Leading
Study
..............3


Climate
Policy
Update.................................4


In
the
News
................................................8


New
Partners..............................................8


Calendar.....................................................9


Partner
Profile


Methane
to
Markets
Project
Network



Member
Eni
Shares
Experiences
and



Goals
in
Reducing
Methane
Emissions



As a project network member, 

Eni demonstrates its commitment to the Methane to 

Markets Partnership (M2M) by actively 

supporting the goal of reducing methane emissions through cost­effective, 

near­term methane recovery and use. 

Eni
is
an
integrated
energy
company
with


assets
in
oil
and
natural
gas
market
segments


that
include
exploration,
production,
transportation,
and
distribution.
Eni
is
based
in
Italy,
is


active
in
70
countries,
and
has
been
participating
in
Methane
to
Markets
since
2005
in
the
oil


and
gas
subcommittee.


Last Spring the Italy­based energy 

company shared information on several 

methane emission reduction projects 

underway during the M2M Oil & Gas 

Subcommittee Meeting in Rome, Italy. 

In this way, Eni is one entity contributing to the Methane to Markets project 

network. The project network facilitates 

the involvement of key non­governmental organizations, such as the private 

sector and development banks, to participate in M2M meetings and engage 

in project development in coordination 

with Partner countries. 

Continued on page 6 H H H 

Natural Gas STAR Partner Update H Spring 2009 1 
practices for implementation. Annual 

report content is also a factor for the 

achievement awards given in the fourth 

quarter of each year at the annual 

implementation workshop. 

Reporting Templates 

epa.gov/gasstar/tools/program-forms.html 

Gathering and Processing Sector 

Annual Report OMB Control No. 2060-0328 

Expires 07/31/2011 

BMP 1: Convert Gas Pneumatics to Instrument Air Systems 

Current Year Activities 

A. Facility/location identifier information: 

systems 

devices 

B. Facility summary: 

Number of instrument air systems 

installed: 

Total number of high-bleed devices in 

systems converted to instrument air, if 

known: devices 

Total number of low-bleed devices in 

systems converted to instrument air, 

if known: 

Percentage of facilities using 

instrument air: % 

C. Cost summary: 

Estimated cost of converting to instrument air (including equipment and labor): $ /replacement 

D. Methane emissions reduction: Mcf E. Are these emissions reductions a one-year reduction or a 

multi-year reduction? One-year Multi-year 

If Multi-year: 

Partner will report this activity once and let EPA 

automatically calculate future emission reductions based on 

sunset date duration (BMP 1 has a sunset period of 10 

years). 

Partner will report this activity annually up to allowed sunset 

date. 

Please identify the basis for the emissions reduction estimate, using the space provided to show any calculations 

Direct measurement 

Total volume of gas used per year prior to 

converting to instrument air: 

Standard calculation 

Methane emissions reduction = [Average high-bleed 

device annual emissions (Mcf/yr) x Number of high-bleed 

devices conv erted to instrument air] + [Average lowbleed device annual emissions (M cf/yr) x Number of lowbleed devices converted to instrument air] 

Please specify your data source: 

o Field measurement 

o Manufacturer specifications 

Other (please specify): 

For assistance quantifying the methane 

emission reductions achieved by BMP 1, 

please refer to the Gas STAR Emission 

Reduction Quantification Reference Guide, 

available on the Gas STAR Web site at: 

epa.gov/gasstar/documents/xls/quantifying_ 

ngs_methane_reductions.xls. 

F. Total value of gas saved: 

Total value of gas saved = Methane emissions 

reduction (in Mcf) x Gas value (in $/Mcf) [If not 

known, us e default of $7.00/Mcf] 

$ G. How many instrument air 

replacements are planned for 

next year? installations 

Previous Years' Activities 

Use the table below to report any past activities implemented, but not previously reported to the Natural Gas STAR Program 

BMP 1 Comments: Please use the back of the page for additional space if needed. 

*If annual emissions are not 

known, use default values of 138 

Mcf/yr for high-bleed device 

emissions and 14 Mcf/yr for lowbleed device emissions 

Reporting
Resources


Technical Documents 

Lessons 

Learned 

From Natural Gas STAR Partners 

DIRECTED INSPECTION AND MAINTENANCE AT GAS 

PROCESSING PLANTS AND BOOSTER STATIONS 

Executive Summary 

Natural gas processing plants and their associated compressor booster stations emit an estimated 36 billion 

cubic feet (Bcf) of methane annually. More than 24 Bcf of tota l methane losses from gas plants are fugitive emissions from leaking compressors and other equipment components such as valves, connectors, seals, and openended lines. Implementing a directed inspection and maintenance (DI&M) program is a proven, cost­effective way 

to detect, measure, prioritize, and repair equipment leaks to reduce methane emissions. 

A DI&M program begins with a baseline survey to identify and quantify leaks. Repairs are then made to only the 

leaking components that are cost­effective to fix, based on criteria such as repair cost, expected life of the repair, 

and payback period. Subsequent surveys are designed based on data from previous surveys, allowing operators 

to concentrate on the components that are most likely to leak and are profitable to repair. Baseline surveys of 

Natural Gas STAR partners' gas processing facilities found that the majority of fugitive methane emissions are 

from a relatively small number of leaking components. Valves are the largest source (30 percent), followed by 

connectors (24 percent), and compressor seals (23 percent). The remaining 23 percent of methane losses are 

primarily from open­ended lines, crankcase vents, pressure relief devices, and pump seals. 

Natural Gas STAR processing partners have reported significant savings and methane emissions reductions by 

implementing DI&M. A four­plant pilot study conducted by EPA and the Gas Technology Institute (GTI) demonstrated that instituting a DI&M program at gas processing facilities could reduce methane emissions by up to 96 

percent and save up to $164,000 per plant. 

This is of series of Lessons Learned Summaries developed by EPA in cooperation with the natural gas industr superior 

applications of Natural Gas STAR Program Best Management Practices (BMPs) and Partner Reported Opportunities (PROs). 

epa.gov/gasstar/tools/recommended.html 

Taking
Credit
for
Your
Accomplishments:
Annual



Reporting
Key
Dates
and
Resources



The 2009 annual reporting 

cycle for Natural Gas STAR 

Partners is underway, and 

Implementation Managers can take 

advantage of Program resources to 

streamline the process. The annual 

report is the capstone of each year’s 

Natural Gas STAR participation, providing a permanent record of the 

voluntary efforts undertaken by each 

Partner and informing EPA of new 

methane emission reduction technologies and practices. 

Annual reporting is a major driver for 

Natural Gas STAR to support Partners. 

It is the source of new project ideas 

and the way the Program communicates the collective success of Partner 

companies. Reporting is an essential 

activity for each Partner because it 

documents emission reduction achievements, demonstrates to company staff 

the value of participation over the last 

year, and brings new ideas to the technology transfer process. Annual reports 

require a signature this year. 

Support
Natural
Gas


STAR
activities
by


submitting
new
and


innovative
ideas
within


or
in
addition
to
your


annual
reports


H Do
you
have
an
idea
for
a
new
methane
emissions
reduction
method?


H Can
you
share
your
new
ideas
or
past


experiences
at
an
upcoming


workshop?


Partner
companies
are
our
biggest
advocates.
By
sharing
thoughts
and
ideas,


companies
can
help
Natural
Gas
STAR
to


diversify
Program
support
products,
reach


new,
existing
and
potential
Partners,
and


strengthen
the
overall
Program.


Submittal
Options


H Online db2.erg.com/gasstar/login.asp


H Email or hard copy Find
your
designated
EPA
Program
Manger


Click
their
name
for
contact
info
at
epa.gov/gasstar/partners/index.html


Timeline 

In early 2009, Partners begin organizing methane emission reduction data 

for the 2008 calendar year—identifying 

locations with voluntary project work 

and listing specific projects undertaken. 

Partners are free to use any convenient 

reporting format including hardcopy 

annual reporting forms available for 

download from the Natural Gas STAR 

web site, online annual reporting forms, 

worksheets, or text documents. If you 

do choose to submit your data in a 

custom format, please ensure that it 

includes all of the data that is requested 

in our standard forms. 

In late­March, Partners receive an 

annual reporting package in the mail 

which provides detailed reporting 

instructions. Reports are due to Natural 

Gas STAR by April 30, 2009, and can 

be sent via email, fax, standard mail, or 

using the secure, password­protected 

online annual reporting forms. 

Natural Gas STAR reviews each annual 

report after it is submitted and makes 

a record of methane emissions reductions for each Partner. In the fall, 

Partners who submitted annual reports 

on time will receive a Natural Gas STAR 

summary report. This report is based 

on the Partner’s annual report data 

throughout participation in Natural Gas 

STAR and is designed to help Partners 

assess their accomplishments and 

explore additional technologies and 

Year # Units Replaced Total Cost of Replacements 

(incl. equipment and labor) ($) 

Estimated Reductions 

(Mcf/yr) 

Value of Gas 

Saved ($) 

Leak Source Fugitive 

Methane 

Emissions 

Method for 

Reducing 

Methane Loss 

Potential 

Emissions 

Reduction 

Typical Implementation 

Cost 

Typical Partner 

Savings (at $3/Mcf) 

Fugitive Methane 

Emissions from 

Gas Processing 

Plants and 

Booster Stations 

45,000 to 

128,000 Mcf/yr 

per gas plant 

Directed 

Inspection & 

Maintenance 

Up to 96 percent; 

average 77 

percent 

$14,000 to $50,000 for 

leak screening and 

measurement; $39,000 to 

$78,000 for repairs 

$58,000 to $164,000/yr 

per gas plant 

Continued on page 3 H H H 

2 Natural Gas STAR Partner Update H Spring 2009 
Annual
Reporting


Continued from page 2 H H H 

Resources 

Partners can take advantage of a suite 

of Program resources to expedite 

annual reporting. Reporting templates 

provide an existing format and default 

values for different project types. 

The emission reduction quantification 

reference guide provides a comprehensive list of recommended reduction 

methods and different approaches for 

calculating methane savings from each 

project type. Natural Gas STAR technical documents describe specific reduction methods in detail, including methods for estimating costs, cost savings, 

and methane savings. 

Reporting Tips 

Partners have developed several strategies for gaining the most benefit from 

the annual reporting process. Some 

Quantification Guide 

epa.gov/gasstar/documents/xls/quantifying_ 

ngs_methane_reductions.xls 

Reporting
Resources


Partner Challenge service for 

the upcoming reporting year 

epa.gov/gasstar/tools/partner-challenge.html 

Partners use custom reporting formats 

such as spreadsheets that complement 

the format of other internal data systems such as greenhouse gas inventories. Partners have used annual report 

data as a centerpiece to publicize, 

either internally or externally, company 

efforts to reduce methane emissions. 

The annual report has also served as 

a rally point and roadmap from which 

Partners begin to plan reduction projects for the upcoming year. 

Finally, Partners have taken advantage 

of Program services to organize the 

annual reporting process. For example, 

the Partner Challenge service offered 

by the Program helps companies to 

inventory methane emissions reductions, identify previously implemented 

projects to include in annual reports, 

and study the feasibility of selected new 

project types. 

University
of
Texas
Leading
Study


to
Update
Selected
Natural
Gas


Emission
Factors



In 2008, EPA awarded a $500,000 

cooperative agreement to the University 

of Texas at Austin (UT) for the project 

“GHG Emission Factor Development 

Project for Selected Sources in the 

Natural Gas Industry.” The awarding 

of this cooperative agreement was the 

result of a multi­year collaborative process between the EPA, the American 

Petroleum Institute, the Interstate 

Natural Gas Association of America and 

the American Gas Association, to identify existing methane emission factors 

that were high priorities for future study 

and revision. The sources under study 

were selected due to such factors as 

their relative size in the U.S. inventory 

of methane emissions from the oil and 

gas industry, the uncertainty bounds of 

existing emission factors, and known 

changes in common practice in the 

natural gas industry. Table 1 lists the 

factors under study. 

The project team at UT, working with 

URS Corporation, initiated the work by 

completing a literature review of existing emission factors, with the goal of 

identifying any new data sources and 

Table 1. Priority List of Emission Sources for the 

Development of Default Methane Emission Factors 

Industry Emissions Sources 

Segment 

Production Well Clean Ups 

Completion Flaring 

Well Workovers 

Pipeline Leaks 

Processing Reciprocating Compressors 

(fugitive) 

Centrifugal Compressors (fugitive) 

Transmission Reciprocating Compressors 

and Storage (fugitive) 

Pneumatic Devices (vent) 

Centrifugal Compressors – 

Transmission (fugitive) 

Centrifugal Compressors – 

Storage (fugitive) 

Distribution Meter and Regulating Stations 

Residential Customer Meters 

Mains – Plastic 

Services – Plastic 

Continued on page 4 H H H 

Natural Gas STAR Partner Update H Spring 2009 3 
Climate
Policy
Update


EPA
Proposes
First
National
Reporting
on
Greenhouse



Gas
Emissions


On March 10, 2009, the U.S. 

Environmental Protection Agency (EPA) 

proposed the first comprehensive 

national system for reporting emissions 

of greenhouse gases (GHGs) produced by major sources in the United 

States. The proposed rule (40 CFR 98) 

would apply to suppliers of fossil fuel 

and industrial chemicals, manufacturers of motor vehicles and engines, as 

well as large direct emitters of greenhouse gases with emissions equal to 

or greater than a threshold of 25,000 

metric tons of carbon dioxide equivalent per year. This threshold is roughly 

equivalent to the annual greenhouse 

gas emissions from just over 4,500 

passenger vehicles. The vast majority of 

small businesses would not be required 

to report their emissions because their 

emissions fall well below the threshold. Approximately 13,000 facilities, 

University
of
Texas


Continued from page 3 H H H 

studies that had been developed since 

the publication of a comprehensive set 

of factors for natural gas industry 

equipment and operations in 1996 by 

EPA and the Gas Research Institute 

(GRI, now the Gas Technology Institute, 

GTI). The literature review found that, 

in many cases, the GRI study is still the 

primary source for emission factors. 

The full review is posted on the project 

Natural Gas STAR Partner Update H Spring 2009 

accounting for about 85 percent to 90 

percent of greenhouse gases emitted 

in the United States, would be covered 

under the proposal. 

For more information on how the proposed rulemaking affects the oil and 

natural gas industry, please visit EPA’s 

web site at epa.gov/climatechange/ 

emissions/ghgrulemaking.html. The following information is available on 

the web site: 

H Preamble and Proposed Mandatory 

GHG Reporting Rule text; 

H Information sheets for each of the 

source categories covered in the 

proposed rule; 

H Frequently Asked Questions; 

H Information on the public comment 

period including direction for submitweb site, utexas.edu/research/ceer/GHG. 

Based on this review, the team developed a plan for the first round of new 

data acquisition, which will seek to 

study emissions from reciprocating 

compressors in the processing sector. 

UT is working collaboratively with 

industry on this effort and in January 

held several conference calls to review 

findings of the literature study and 

solicit feedback on the initial data 

gathering plan. 

The next steps in this work will be to 

test the preliminary sampling plan for 

ting written comments as well as 

location, dates, and registration for 

two upcoming hearings. 

Public Comment Period 

The public comment period is open 

for 60 days following publication in the 

Federal Register. There are instructions 

on the web site for how to submit written comments. There will also be two 

public hearings for the proposed rule: 

H April 6 and 7, 2009, at EPA 

Potomac Yard Conference Center, 

Arlington, VA; 

H April 16, 2009, at Sacramento 

Convention Center, Sacramento, CA. 

EPA encourages those who wish to 

attend or give public comments, to 

visit the web site and register on­line in 

advance of the hearing. 

compressors with a field trial, and to 

assemble equipment population data 

to develop sampling plans that will lead 

to representative field measurements. 

To enhance this work, UT welcomes 

industry input on this process. In particular, anyone with specific information on 

equipment populations for processing 

sector reciprocating compressors (or 

other selected sources under study) or 

oil and gas companies that are willing to 

offer their sites for participation in sampling are encouraged to contact David 

Allen of UT at allen@che.utexas.edu. 

4 
New
Projects
Spotlight


Continued from page 1 H H H 

source through a basic design change 

with low capital costs. This project type 

could turn large releases of methane 

into an energy supply for fueling onsite 

heaters and boilers. 

This article describes the potential 

new method to capture emissions 

from wet seal compressors and seeks 

feedback from Partners on the feasibility of implementing this type of 

project. It is estimated that recovery, 

treatment, and use of these emissions 

in low pressure fuel systems could 

pay back the investment within one 

month by displacing fuel gas. 

Background: Methane 

Emissions from Wet Seal 

Centrifugal Compressors 

Figure 1 shows methane emissions 

from a typical centrifugal compressor 

using seal oil. These wet seal centrifugal 

compressors circulate oil under high 

pressure between three rings around 

the compressor shaft, forming a barrier 

against the compressed gas to prevent 

its escape to the atmosphere. The center ring is attached to the rotating shaft, 

while the two rings on each side are 

stationary in the seal housing, pressed 

against a thin film of oil flowing between 

the rings to both lubricate and act as 

a leak barrier. Very little gas escapes 

through the oil barrier, but a significant 

amount of gas is absorbed by the oil 

on the compressor side of the seal at 

the oil interface with high pressure gas, 

thus contaminating the seal oil. Seal 

oil must be purged of the absorbed 

gas to maintain viscosity and lubricity when recirculated. This is done in a 

flash drum or oil sump. The methane 

degassed from the seal oil is typically 

emitted to the atmosphere through an 

open ended line. 

Methane emissions from seal oil degassing of one typical centrifugal compressor range from 40 to 200 standard 

cubic feet (scf) methane per minute. 

Given an average methane emissions 

of 120 scf per minute, the volume of 

methane lost represents $442,000 per 

year at an average gas value of $7 per 

Previously
Reported



Reduction
Method:



Replace
Wet
Seals
with



Dry
Seals



One
existing
mitigation
option
reported


by
many
Natural
Gas
STAR
Partners
is
to


retrofit
a
compressor
with
dry
seals,
which


replaces
the
wet
seal
system
with
springloaded,
grooved
seals
that
create
hydrodynamic
gas
pressure
as
a
barrier
to
prevent


gas
leaks
along
the
shaft.
Depending
on


the
size
and
pressure
of
the
compressor,


dry
seals
typically
leak
at
a
rate
of
0.5
to


3
scf
per
minute,
resulting
in
a
substantial
reduction
in
methane
emissions
as


compared
to
wet
seal
configurations.
This


substantial
methane
savings
technology


requires
a
high
initial
capital
investment
but


has
a
lower
operating
cost
than
wet
seals


and
pays
back
within
8
to
24
months.
Dry


seal
retrofits
might
not
be
possible
on
some


compressors
due
to
compressor
housing
design
or
operational
requirements.


Companies
can
evaluate
whether
retrofitting
centrifugal
compressors
makes
sense


based
on
individual
operating
conditions


and
corporate
resources.
For
more
information,
visit
epa.gov/gasstar/documents/


ll_wetseals.pdf.


thousand scf (Mcf). 

New Opportunity: Seal Oil 

Degassing Vent Recovery and Use 

A new, less capital intensive solution 

could be to reduce emissions from seal 

oil degassing through capture and use 

of the methane. A diagram illustrating 

this new method is shown in Figure 2. 

Seal oil contaminated with gas that is 

typically sent to the atmospheric degassing drum is instead degassed at a new 

drum operating at fuel pressure. 

Continued on page 7 H H H 

Gas vent to 

atmosphere 

Seal oil 

degassing 

drum 

New fuel pressure 

seal oil degassing 

Less gas 

vented to 

atmosphere 

Seal oil 

degassing 

drum Low pressure 

fuel gas 

Boiler 

Seal oil circulation pump 

drum and demister 

Seal oil circulation pump 

Note: New equipment in red 

Figure 1. Wet Seal Centrifugal Compressor Figure 2. Centrifugal Compressor Seal Oil Flash Gas Recovery and Use 

Natural Gas STAR Partner Update H Spring 2009 5 
Partner
Profile


Continued from page 1 H H H 

Managing Fugitive Emissions from 

Transmission and 

Distribution Systems 

A focus of Eni’s methane emissions 

reduction program is fugitive monitoring and repair. Eni began this effort by 

identifying emissions sources and estimating fugitive emissions at selected 

compressor stations. The next step 

was the development of a tool to prioritize and plan work and maintenance 

activities for significant emissions 

sources. The results from monitoring 

three compressor stations were generally consistent, showing instrumentation 

and flanges as having the highest emissions of the four categories of sources 

monitored, accounting for 80 percent of 

total emissions. 

Eni also studied its natural gas distribution system and determined that methane leaks primarily occur at pipe joints 

Currently,
Eni
is
using
FT-IR
at
its
offshore
 Utilizing
Leak
Detection
 and
onshore
facilities
worldwide
to
estimate
 Technologies
 the
effectiveness
of
emission
reduction


activities.


Eni
uses
the
Sherlock®
infrared
leak
imaging
 The
FT-IR
remote
sensing
system
can
be
 camera
to
remotely
monitor
emissions.
Leak
 used
in
either
a
passive
or
active
mode
to
 imaging
has
been
a
means
for
Eni
to
identify
 detect
criteria
pollutants
and
greenhouse
 and
locate
leaks,
to
prioritize
maintenance
 gases.
It
works
on
the
principle
of
absorp- and
repair
work,
and
for
demonstrating
the
 tion
of
infrared
radiation
to
measure
the
 effectiveness
of
methane
emission
reduction


concentration
of
gas
pollutants.
The
system
 activities.
Additionally,
video
imaging
has
 uses
algorithms
to
account
for
background
 given
Eni
the
ability
to
detect
emissions
in
 (meteorological
and
atmospheric)
conditions
 areas
that
are
not
easily
accessible.
 and
other
factors
(geometric
parameters)
that
 Eni
estimates
its
greenhouse
gas
emissions
 influence
the
results.
Through
all
these
activi- following
an
international
monitoring
and
 ties,
Eni
has
noted
an
element
of
uncertainty
 reporting
protocol1
 and
simultaneously
carries
 associated
with
emissions
measurements


out
several
field
measurement
campaigns
to
 and
has
recognized
the
need
for
protocols
 evaluate
and
control
the
estimation
uncer- and
validation
to
reduce
this
uncertainty.
 tainty
level.
To
do
this,
Eni
uses
the
Fourier
 The
Methane
Emissions
Leaks
Detection


Transform
Infrared
Spectroscopy
(FT-IR)
 and
Recovery
program
is
supported
by
a
 remote
sensing.
FT-IR
is
a
way
to
character- experts
group
of
the
Eni
Research
Center
for
 ize
point
source
emissions
without
an
actual
 Environmental
Technologies.
 sampling
port
(chimney,
stack
or
flare).


as a result of traffic stress and third 

party damage. To address this, Eni 

identified the main ways it could reduce 

leaks, specifically through: 

H replacement of aged in­service pipe 

with steel or plastic pipe; 

H “conditioning” of aged in­service 

lead / yarn jointed pipes that have 

become unsealed by adding water 

vapor or monoethylene glycol into 

the pipe; 

H prevention of third party damage 

through outreach and education. 

Through these measures, Eni hopes to 

reduce emissions from Italgas—Eni’s 

distribution system for Rome—by 

approximately 60 percent from1990 

levels by the year 2014. 

2007 Results and Plans 

for the Future 

Although Eni reported a 10 percent 

increase in greenhouse gas emissions 

in 2007 (including methane) largely due 

to the acquisitions of new assets (e.g. 

in Congo and Russia), over the last 

five years emissions of carbon dioxide 

equivalents (CO2

e) in exploration and 

production, refining and marketing and 

gas and power business units have registered substantial emissions reductions. 

In addition to ongoing fugitive methane 

emissions reduction activities, longterm flaring projects are expected to 

Continued on page 10 H H H 

6 Natural Gas STAR Partner Update H Spring 2009 
New
Projects
Spotlight


Continued from page 5 H H H 

The absorbed methane vaporizes out 

of solution in the intermediate pressure 

drum and is used in a facility’s fuel gas 

system. The seal oil then flows to the 

final degassing stage where a minimal 

volume of methane is degassed to the 

atmosphere and the regenerated seal 

oil is recirculated to the compressor. 

Seal oil exits a compressor at a typical pressure of 400 pounds per square 

inch gauge (psig). Operating the degassing drum at 50 psig results in nearly 

all of the seal oil degassing emissions 

to be recovered to fuel gas. At an average seal emissions rate of 120 scf per 

minute this steady supply of gas is sufficient to meet the fuel requirements of a 

boiler or other equipment with an input 

heat duty of about 7 million British thermal units (Btu) per hour assuming a gas 

heat content of 1,000 Btu per scf. 

Sites must meet several operating 

requirements to implement this recovery and use of seal oil flash gas. On­site 

equipment or a low pressure fuel gas 

system must be nearby that can accept 

and use the low pressure gas stream. 

The flash gas stream will entrain small 

amounts of seal oil, requiring a demister/filter or fuel gas knock­out vessel to 

remove this entrained oil and yield an 

acceptable fuel gas specification. 

Example Implementation 

and Economics 

The investment to recover seal oil 

degassing emissions in this way 

would include the cost of the intermediate pressure degassing drum, 

new piping, gas demister/filter, and 

possibly a pressure regulator for the 

fuel gas line. Using Guthrie’s modular 

method of equipment cost estimation1

, and assuming a typical seal oil 

flow rate of 3.75 gallons per minute, 

the installed cost of equipment would 

be about $22,000 if suitable combustion equipment is already in place. 

Operating and maintenance costs are 

expected to be minimal. 

Operating cost savings for capturing 

seal oil degassing emissions are realized by reducing consumption of site 

fuel gas. For one wet seal compressor, 

potential savings can be estimated at 

63 MMcf methane per year, displacing 

this same volume in fuel gas. At $7 per 

Mcf, savings from reduced site fuel gas 

consumption will approach 100 percent 

of the seal oil emissions or $442,000. 

Example project economics are shown 

in the project summary box showing an 

estimated payback period of 1 month. 

Conclusion 

Capture and use of seal oil degassing 

emissions is a project option less capital intensive than the alternative of retrofitting centrifugal compressors with dry 

seals. Routing seal oil methane emissions to fuel gas is an opportunity to 

convert a potential climate change liability into a site efficiency improvement as 

well as a project with positive cash flow 

after the first month. 

We would like to hear from you on the 

feasibility of implementing this type of 

project. Or if your company has already 

implemented this practice and is willing to share your experiences with the 

Natural Gas STAR Program, please 

contact Suzie Waltzer, EPA 

[Waltzer.Suzanne@epamail.epa.gov or 

(202) 343­9544]. 

PROJECT SUMMARY: CAPTURE AND USE OF 

SEAL OIL DEGASSING EMISSIONS 

Operating 

Requirements 

• Centrifugal compressor with

seal oil system 

• Nearby use for low pressure

fuel gas 

• New intermediate pressure

flash drum, fuel filter,

pressure regulator 

Capital & 

Installation Costs 

$22,000

Annual Labor & 

Maintenance Costs 

Minimal 

Methane saved 63 MMcf per year 

Gas Price per Mcf $3 $7 $10

Value of Gas 

Saved 

$189,000 $442,000 $631,000

Payback Period 

in Months

2 1 0.5

1 Biegler, et al. “4.3.1 Guthrie’s Modular Method.” 

Systematic Methods of Chemical Process Design. 

Ed. Neal R. Amundson. Saddlewood: Pearson, 

1997. pages 133 to 135 

Natural Gas STAR Partner Update H Spring 2009 7 
In
the
News



Satellite
Launched
to
Observe
Methane
from
Oil
and
Gas



EPA
is
excited
to
announce
the


addition
of
several
new
Partners
to


the
Natural
Gas
STAR
Program.


INTERNATIONAL PARTNER 

GAZ SYSTEM S.A. 

GAZ-SYSTEM
S.A.,
headquartered
in


Warsaw,
is
a
state
company
that
operates


Poland’s
domestic
gas
transmission
pipe


lines.
Established
in
2004,
the
company


transports
natural
gas
through
networks


with
973
exit
points.
As
of
January
2009,


GAZ
 SYSTEM
operated
a
9,803
 kilometer


transmission
network
transporting
14.7
bil


lion
cubic
meters
(519
billion
cubic
feet)
of


gas
annually.
The
company
has
an
agree


ment
for
use
of
1.66
billion
cubic
meters


(58.6
billion
cubic
feet)
of
gas
storage


capacity
for
peak
shaving
and
other
pur


poses.
GAZ
 SYSTEM
S.A.
joins
nine
other


Natural
Gas
STAR
International
Partners
in


the
effort
to
identify
and
implement
costeffective
methane
emission
reduction
proj


ects
in
the
oil
and
natural
gas
industry.
For


further
information
on
the
company,
visit


www.gaz-system.pl


DOMESTIC PARTNERS 

HighMount Exploration & Production LLC 

HighMount
Exploration
&
Production,


headquartered
in
Houston,
Texas,
is
a


subsidiary
of
Loews
Corporation
and
one


of
the
20
largest
holders
of
domestic


natural
gas
reserves.
With
assets
located


in
the
Permian
Basin
in
Texas,
the
Antrim


Shale
of
the
Michigan
Basin,
and
the
Black


Warrior
Basin
in
Alabama,
HighMount


has
4.7
trillion
cubic
feet
equivalent
of


proved,
probable,
and
possible
natural
gas


reserves.
HighMount’s
645
employees
are


focused
on
the
development
and
production


of
natural
gas.
For
further
information
on


the
Partner,
please
visit
highmountep.com.


Prism Gas Systems I, LP 

Prism
Gas
Systems
I,
LP
and
its
subsidiar


ies
provide
midstream
natural
gas
services,


including
gathering,
processing,
and
treating


of
natural
gas,
as
well
as
treating,
fraction


ation,
and
stabilization
of
natural
gas
liquids.


Headquartered
in
Bedford,
Texas,
Prism


has
ownership
interests
in
approximately


659
miles
of
gathering
and
transmission


pipelines
located
in
the
natural
gas
pro


ducing
regions
of
Central
and
East
Texas,


Northwest
Louisiana,
and
the
Texas
Gulf


Coast
and
operates
a
265
million
cubic
feet


per
day
natural
gas
processing
plant
in
East


Texas.
For
more
information,
please
visit
the


Partner’s
Web
site
at
prismgas.com.


Systems


The Japan Aerospace Exploration 

Agency (JAXA) launched the 

Greenhouse Gases Observing Satellite 

(GOSAT), on January 23, 2009. GOSAT 

is dedicated to detecting greenhouse 

gases from space. It collects data on 

the presence of greenhouse gases 

within an observation area by detecting the infrared radiation absorbed by 

both methane and carbon dioxide. For 

the oil and natural gas industry, GOSAT 

can periodically monitor emissions from 

infrastructure such as pipelines, compressor stations, and other facilities. 

According to JAXA, the GOSAT satellite 

will be the first dedicated observation 

station capable of monitoring greenhouse gases, and it will monitor 56,000 

observation points over the entire globe 

from a polar orbit with a three day 

repeat. The system can observe methane and carbon dioxide releases with 

a spatial resolution of ten kilometers 

compared with widely used technologies today that have a spatial resolution 

of about 100 kilometers. Data from 

GOSAT will be made accessible to the 

public free of charge through a dedicated web site starting around September 

2009. For more information about the 

GOSAT program, visit 

jaxa.jp/countdown/f15/index_e.html. 

8 Natural Gas STAR Partner Update H Spring 2009 
In
the
News


Report
Discusses


Emissions


and
Control


Technologies
for


Barnett
Shale


Production


In January, the Environmental Defense 

Fund released a report quantifying 

emissions from the Barnett Shale production area and summarizing emissions control measures. 

The report entitled, “Emissions from 

Natural Gas Production in the Barnett 

Shale Area and Opportunities for CostEffective Improvements” quantifies both 

greenhouse gas emissions and criteria 

pollutants for 2007 and for 2009 in the 

21­county Barnett Shale area. 

The study constructed emissions 

estimates using data from the 

Texas Railroad Commission, Texas 

Commissions on Environmental Quality, 

EPA AP­42, the API Compendium 

of Greenhouse Gas Emissions 

Methodologies for the Oil and Gas 

Industry, the 1996 EPA/GRI report 

Methane Emissions from the Natural 

Gas Industry, and Natural Gas STAR 

Program technical documents. The 

report discusses several Barnett Shale 

emissions reduction opportunities 

based on established types of reduction technologies. The report is available 

at edf.org/documents/9235_Barnett_ 

Shale_Report.pdf. 

Calendar

2009 Upcoming 

Events 

Below
are
scheduled
Natural
Gas
STAR
Program


events.
For
updates
and
further
information,
visit


epa.gov/gasstar/workshops
or
contact
Suzie


Waltzer
at
Waltzer.Suzanne@epa.gov
or


(202)
343-9544.
Additionally,
are
you
a
Natural


Gas
STAR
endorser
and
have
an
event
you
would


like
listed
here?
Please
notify
Natural
Gas
STAR.


Oil and Gas 

Subcommittee Meeting 

Banff,
Alberta,
Canada


14
to
17
Sept,
2009


Production 

Oklahoma
City,
OK


May
14,
2009


Annual Implementation 

Workshop 

San
Antonio,
TX


Oct
19
to
21,
2009


Production and 

Processing 

Billings,
MT


Aug
31,
2009


M2M presentation at 

ARPEL Conference 

Punta
del
Este,
Uruguay


23
to
24
April,
2009


For more information, visit epa.gov/gasstar/workshops 

Natural Gas STAR Partner Update H Spring 2009 9 
Partner
Profile


Continued from page 6 H H H 

result in a 60 percent emissions reduction by 2011 compared to 2007 levels. 

The reduction of emissions from natural 

gas flaring is particularly difficult in areas 

where there is an absence of adequate 

infrastructure, posing barriers to use 

of the natural gas produced from oil 

extraction. Eni promotes the continuous reduction of flaring and venting 

by means of developing natural gas 

pipelines and LNG terminals and using 

the associated natural gas for generating electricity to satisfy local demand. 

Over the next few years, Eni hopes to 

significantly reduce greenhouse gas 

emissions from flaring in several regions 

including the Congo, Nigeria, Libya, 

Tunisia and Algeria. 

Moreover Eni promotes company 

knowledge management through a 

virtual Community of Practice on “Air 

Emissions” with the following main 

objectives: share experiences and collaborate in the development of new 

initiatives, support these activities with 

new tools and the application of best 

available technologies. 

To view Eni’s presentations from the 

Methane to Markets Oil and Gas 

Subcommittee Meeting in Rome, Italy, 

please visit: methanetomarkets.org/ 

events/2008/oilgas/oilgas­20may08.htm 

1 American Petroleum Institute (API), The API 

Compendium of Greenhouse Gas Emissions 

Estimation Methodologies for the Oil and Gas 

Industry; 

Intergovernmental Panel on Climate Change (IPCC). 

Greenhouse Gas Inventory Reference Manual: IPCC 

Guidelines for National Greenhouse Gas Inventorie 

E&P Forum. Methods for Estimating Atmospheric 

Emissions from E&P Operations; 

GRI, GRI-GHGCalcTM; 

US Environmental Protection Agency (EPA). 

Compilation of Air Pollutant Emission Factors; 

US Environmental Protection Agency (EPA). Protocol 

for Equipment Leak Emission Estimate – TANKS; 

Others similar protocol references 

Natural
Gas
STAR



Contacts



Program
Managers


Jerome Blackman H (202)
343-9630


blackman.jerome@epa.gov


Carey Bylin H (202)
343-9669


bylin.carey@epa.gov


Roger Fernandez H (202)
343-9386


fernandez.roger@epa.gov


Suzie Waltzer H (202)
343-9544


waltzer.suzanne@epa.gov


Natural
Gas
STAR
Program



U.S.
Environmental
Protection
Agency



1200
Pennsylvania
Ave.,
NW
(6207J)



Washington,
DC
20460



For
additional
information



on
topics
in
this
Update,



please
contact
Suzie
Waltzer.



10 Natural Gas STAR Partner Update H Spring 2009