NaturalGas(\
EPA POLLUTION PREVENTER *
Partner Update
Winter 2010
2010 Natural Gas STAR Award Winners
The Natural Gas STAR Program recognized the following leaders at this year's Annual
Implementation Workshop. Awards were based on reported methane emission reductions
achieved, range of different methods to reduce methane emissions, and general involvement in
the Program, as well as other innovative company initiatives to minimize methane emissions.
Production Partner of the Year
E! Paso E&P
Since joining Natural Gas STAR in 2003, El Paso E&P and its parent company, the El Paso
Corporation, have been active participants in the Program. El Paso E&P is one of North
America's largest domestic independent
El Paso E&P's Alan Gradet (right) with EPA Natural
Gas STAR Program Representative Scott Bartos,
natural gas producers, operating in key
natural gas basins onshore in the United
States and offshore in the Gulf of Mexico. El
Paso E&P reports a wide variety of methane
emissions reduction activities each year,
including installing gas lifts, converting
pneumatic devices to instrument air,
installing vapor recovery units, replacing and
repairing pipeline, and using foaming agents
to reduce well blowdown emissions. El Paso
E&P has been the top performer in the
production sector for the past two years and
has presented at the 2008 and 2009 Natural
Gas STAR Annual Implementation
Workshops.
Gathering and Processing
Partner of the Year
ONEOK Partners
ONEOK Partners is a leader in gathering,
processing, storing, and transporting natural
gas in the United States. The company's
gathering and processing segment contracts
with exploration and production companies
that gather and process natural gas
produced in areas where ONEOK gathering
systems are located. The company joined
Natural Gas STAR in 2000 and won the
2008 gathering and processing Partner of
sssA ™,sra,e
*
ONEOK's Jim Haught (right) with EPA Natural Gas
STAR Program Representative Scott Bartos.
-------
the Year award. Since joining the Program, ONEOK Partners has demonstrated a strong
commitment to explore various technologies and practices for reducing methane emissions from
its operations. The company has implemented 14 different technologies and practices, resulting
in significant methane emissions reductions. Such activities include aerial leak detection using
laser and infrared technology, replacing and repairing pipeline, and using hot taps for in-service
pipeline connections.
Transmission Partner of the Year
Kinder Morgan Natural Gas Pipelines
Kinder Morgan is one of the largest natural gas
transporters and storage operators in the
United States, with approximately 24,000 miles
of pipeline in the Rocky Mountains, the
Midwest, and Texas. Over the years, the
company has continually verified and updated
its past data and implemented 12 different
technologies and practices to reduce methane
emissions. The company received the
Transmission Partner of the Year award in
2006, and this year, reported methane
emissions reductions through the
implementation of six activities, including leak
detection using ultrasound, installing electric
compressors, and pipeline pumpdowns.
Kinder Morgan's Thomas Bach (center) and Brad
Stevener (right) with EPA Natural Gas STAR Program
Representative Scott Bartos.
Distribution Partner of the Year
New Jersey Natural Gas
New Jersey Natural Gas operates and maintains a distribution infrastructure to serve nearly half
a million residential, commercial, and industrial customers. The company joined Natural Gas
STAR in 2004 and has continuously explored options for reducing methane emissions from its
operations. In 2009, New Jersey Natural Gas reported implementing five methane emission
reduction technologies and practices and recorded its greatest level of methane emissions
reductions to date. Activities implemented include converting devices from pneumatic to
mechanical/electronic controls, injecting blowdown gas into low pressure systems, installing
excess flow valves, and testing and repairing pressure safety valves.
Implementation Manager of the Year
Mike Pontiff, Newfield Exploration
Mike Pontiff, HSE Engineer at Newfield
Exploration, has been the Implementation
Manager since the company joined Natural
Gas STAR. Prior to this, he was the
Implementation Manager for El Paso E&P.
Mr. Pontiff helped lead Newfield to join the
rogram and to implement a variety of
methane emission reduction technologies
and practices. He is a longtime champion
of Natural Gas STAR'S technology transfer
and information sharing efforts. Mr.
NatuiaIGas<\
sra roLLimoH nmnn '
Newfield Exploration's Mike Pontiff (right) with EPA Natural
Gas STAR Program Representative Scott Bartos. 2
Winter 2010
-------
Pontiff's presentation on "Process Optimization" at the Vernal, Utah Technology Transfer
Workshop and his participation at Newfield's accompanying Pleasant Valley compressor station
site visit were amongst many vital contributions made in 2010. He is a valued resource in
communicating the core principles of Natural Gas STAR.
Rookie of the Year
HighMount E&P
HighMount E&P plays a key role in the
exploration and production of natural gas and
natural gas liquids. HighMount's assets are
largely located in the Permian Basin, Texas.
The company operates approximately 5,800
wells in the Permian Basin region. Since
joining Natural Gas STAR in 2009,
HighMount E&P has implemented several
methane emission reduction technologies
and practices, including identifying and
replacing high bleed pneumatic devices,
installing flash tank separators on glycol
dehydrators, installing plunger lifts, installing
instrument air, eliminating unnecessary
equipment and/or systems, and installing electric motors. The company's first submitted annual
report also included detailed information of past methane emissions reductions.
International Partner of the Year
Oil and Natural Gas Corporation Ltd. (ONGC)
ONGC, a state-owned oil and gas company, is one of Asia's largest exploration and production
companies, operating more than 11,000 kilometers of pipeline and contributing 77 percent of
India's crude oil production and 81 percent of India's natural gas production. Since joining
Natural Gas STAR International in 2007, ONGC has made significant efforts to build a strong
program, focusing on engaging
management, raising awareness of Natural
Gas STAR within the company, providing
specialized training to personnel on Natural
Gas STAR-recommended technologies and
practices, and building internal capacity to
identify and implement methane emission
reduction opportunities within ONGC
operations. EPA and ONGC have
collaborated on prefeasibility studies to
identify and estimate major methane
emission sources from several ONGC sites.
Based on the results of these studies,
ongc staff with EPA Natural Gas star Program several ONGC sites have been identified as
Representatives. candidates that would benefit from further
emission detection and measurement
studies. The company is now implementing methane mitigation projects at three locations.
ONGC was also instrumental in organizing and sponsoring the 2010 Methane to Markets
Partnership Expo in New Delhi, India.
Partner
Winter 2010
HighMount E&P's Ervin Fisher (right) with EPA Natural
Gas STAR Proaram Representative Scott Bartos.
-------
CONTINUING EXCELLENCES YEARS
Natural Gas STAR Partner company staff
with EPA Natural Gas STAR Program
Representative Carey Bylin. The 5-year
Continuing Excellence Partner companies are
Alliance Pipeline LP, Consumers Energy,
Equitable Gas Co., Marathon Oil Company,
New Jersey Natural Gas Company, New
Mexico Gas Company, Nicor Gas, ONEOK
Partners, Panhandle Eastern Pipe Line
Company, and Quicksilver Resources
CONTINUING EXCELLENCE—
7 YEARS
Natural Gas STAR Partner company staff
with EPA Natural Gas STAR Program
Representative Carey Bylin. The 7-year
Continuing Excellence Partner companies
are Devon Energy, Puget Sound Energy, and
Shell Exploration and Production Company
CONTINUING EXCELLENCE—10 YEARS
Natural Gas STAR Partner company staff
with EPA Natural Gas STAR Program
Representative Carey Bylin. The 10-year
Continuing Excellence Partner company is
Hess Corporation's Americas Exploration
and Production.
A Partner Update
Winter 2010
-------
CONTINUING EXCELLENCE—15 YEARS
The 15-year Continuing Excellence Partner companies are Central Hudson Gas & Electric
Corporation, Orange and Rockland Utilities, Inc., and Public Service Electric and Gas Company.
CONTINUING EXCELLENCE—17 YEARS
Natural Gas STAR Partner company staff
with EPA Natural Gas STAR Program
Representative Carey Bylin. The 17-year
Continuing Excellence Partner companies
are Consolidated Edison Company of New
York. Inc., National Grid, UGI Utilities, Inc,
Washington Gas, and Williams Gas Pipeline.
More 2010 Annual Implementation Workshop information, proceedings, and presentations are
available online at epa.gov/qasstar/workshops/annualimplementation/2010.html.
Partner Profile:
Newfield Exploration Company
NEWFIELD
A Natural Gas STAR Partner since 2004, Newfield
Exploration Company (Newfield) is a growing
independent oil and natural gas company with a
program of exploration, production, and acquisitions that
is headquartered in Houston, Texas. Newfield's most
recent activities related to methane emissions
management—hosting a compressor station measurement study and developing a new
corporate inventory tool—are a natural extension of its participation in the Program.
Newfield's current proved reserves total 3.6 trillion cubic feet equivalents and stem from
domestic operations in the Mid-Continent, the Rocky Mountains, onshore Texas, and the Gulf of
Mexico and international operations including offshore Malaysia and China. Approximately 70
percent of the company's reserves are natural gas with 93 percent of the reserves from
domestic U.S. operations.
Newfield has been actively involved in cost-effectively reducing methane emissions since joining
Natural Gas STAR. In 2009, Newfield achieved nearly 1.2 billion cubic feet (Bcf) in methane
emissions reductions, and the company's cumulative reductions total over 5.4 Bcf.
Approximately 78 percent of its methane emissions reductions are the result of the following
activities: 1) installing vapor recovery units (VRUs), 2) installing plunger lifts, and 3) replacing
high bleed pneumatic devices.
Because of its continuing efforts, Newfield has received the 2005 Rookie of the Year award, a
2008 Continuing Excellence Award (5 years), and the 2010 Implementation Manager of the
A Partner Update
Winter 2010
-------
Year award (Mike Pontiff). Recent Natural Gas STAR activities include sponsoring a producers
technology transfer workshop in Vernal, Utah and holding a measurement study/site visit at
Newfield's Pleasant Valley compressor station.
Pleasant Valley Station Survey
In March 2010, Newfield agreed to work with Natural Gas STAR by hosting a technology
transfer workshop in conjunction with a measurement study and site visit to demonstrate tools
and technologies to cost effectively reduce methane emissions. Newfield's Pleasant Valley
Station in the Uinta Basin area of Utah was the survey site. A Natural Gas STAR measurement
study team used the GasFindIR™ infrared camera to identify emission sources and used
turbine meters, calibrated bags, and a Hi
Flow® Sampler to measure the emission
rates. This site visit allowed other Partners to
witness the effectiveness of these
technologies and techniques.
The Pleasant Valley compressor station is a
newly constructed facility and is also an
example of Newfield's Process Optimization
(PRO-OP) approach to reducing methane
emissions. According to Newfield, PRO-OP is
"a systematic approach to increase production
efficiencies and profitability through evaluating
process components, reducing methane
emissions on a cost-effective basis." This
practice aims to get as much product from the wellhead to the sales meter as possible by
considering the process on the whole rather than considering the emissions source in isolation.
For more information on PRO-OP, see Newfield's presentation at a recent Natural Gas STAR
workshop: epa.gov/gasstar/workshops/techtransfer/2010/vernal.html.
The Pleasant Valley Station measurement
study indicated that methane emissions from
Newfield's operations fell into four types of
source categories: 1) pneumatic devices, 2)
leaks, 3) rod packing, and 4) tank vents.
Pneumatic devices accounted for the largest
percentage of methane emissions while the
single condensate tank vent made up the
smallest percentage. Twenty-one individual
leak sources were detected, and 20 could be
targeted with proven best management
practices.
PRO-OP is applicable to both new and old
facilities, helping to identify opportunities such
as eliminating emissions sources, capturing
emissions for sales, or flaring. As a result of
the emissions discovered during the
measurement study, Newfield plans to repair what leaks were found. Since the field study was
conducted at Pleasant Valley, electricity has been run to this facility, and ail pneumatic devices
have been converted to instrument air systems. Also, vent emissions from a single storage tank
A artner Update 6
Winter 2010
Exhibit 1: Workshop site visit attendees inspecting a leak
with the GasFindiR camera at Pleasant Valley station.
Exhibit 2: Measurement experts quantifying a
methane emissions source with the Hi Flow Sampler at
Pleasant Valley station during the Natural Gas STAR
workshop site visit.
-------
are now being routed to a combustor, and the emission volumes are being monitored to
determine the economic feasibility of installing a vapor recovery system.
Corporate Greenhouse Gas Inventory Tool
Another aspect of Newfield's methane emissions management is its recently developed
company-wide process for quantifying and recording greenhouse gas (GHG) emissions from
each facility. The main purpose of this inventory tool is to provide the company with an
"evergreen program that provides near real time data." The motivations for creating and
implementing a corporate inventory included:
• potentially participating in voluntary GHG programs,
• establishing and achieving corporate social responsibility goals regarding carbon
management,
• managing risks and identifying opportunities,
• providing information to stakeholders, and
• preparing for pending federal legislation that might require such tracking.
With these outcomes in mind, the tool has two components which collect, aggregate, and store
a variety of data streams already being generated by Newfield.
The first component is a third party software package possessing the following characteristics:
• dashboard capability,
• capable of providing near real-time data, and
• complete environmental management information system (EMIS) package.
The other component of Newfield's inventory tool is the Carbon System Interface (CSI). It was
generated by Newfield to act as a "bridge" between the variety of existing Newfield data streams
and the third party EMIS package, allowing operators to access daily/monthly data and any new
equipment or process changes.
Capture of Newfield's existing data into
the CSI is an automated process, with
the exception of data for drilling rig
runtimes, electricity usage, certain
venting volumes, and vehicle miles
(contractor and fleet).
The combined two components of
Newfield's inventory tool include both
direct and indirect emissions. Direct
sources are those sources which
Newfield has direct control of in its field
operations. Indirect sources are
typically associated with third party
activity.
One feature of the inventory tool is its ability to generate emissions profiles specific to the
requirements of state, permit, business unit, or other reporting activities. The tool accomplishes
this by building a library of calculation methodologies over a period of time which can be applied
to the Newfield data. Combined with standard accepted manufacturer emissions factors, or
state- or regional-specific factors, different profiles are generated for different contexts.
»t ^ ip Partner Update
^^^47 Winter 2010
Exhibit 3: A screenshot of the Carbon System Interface (CSI),
a component of Newfield's corporate GHG inventory tool.
-------
Orice the tool was completely installed and integrated, Newfield trained its employees on both
the third party EM IS and the CSI software. A QA/QC program oversees the tool, helping to
maintain quality and verification in production accounting, mapping of sources, equations,
profiles, and the CSI itself. With this new GHG inventory tool, Newfield will acquire a more
transparent view of its own emissions to help further its emissions reduction goals.
Outlook for the Future
With these two activities—the Pleasant Valley measurement study and GHG inventory tool—
Newfield is acquiring additional knowledge to make informed decisions on methane emissions
mitigation.
Technology Spotlight:
Casinghead Gas Capture
A common issue encountered by many producers is the buildup of pressure in the casing of a
mature oil well. Increased pressure in the well casing from accumulated gas, in combination
with the surface equipment backpressure, restricts oil flow and decreases production.
Project Description
Using a small wellhead compressor to relieve well
formation pressure can increase oil production and
recover BTU-rich gas for sales or on-site use. The
compressor maintains the casinghead pressure as
close to zero as possible which also stabilizes the
oil line pressure and reduces fluctuations.
Companies have traditionally used skid-mounted
compressors for this project type.
Casinghead gas must be removed to allow an oil well to be most productive. This gas is
typically vented to the atmosphere when the wellhead pressure at the surface drops below the
sales line pressure. The casinghead gas pressure is preferably as close to zero psig as
possible. A cost-effective alternative to venting is casinghead gas capture which has the
benefits of maintaining oil well productivity,
reducing methane emissions, and providing a
source of natural gas which can be put to
beneficial use in a number of ways.
Types of skid-mounted compressors that can be
utilized in this project include: 1) rotary vane, 2)
rotary screw, 3) scroll, and 4) reciprocating. Rotary
vane compressors are generally the most cost-
effective when handling wet casinghead gas (this
gas is normally wet because it flashes off the oil
reservoir and typically has a specific gravity of
around 0.85 [16 gallons of liquid per thousand
cubic foot (Mcf) gas]). Scroll compressors can
handle wet gas and were covered by a previous
Partner Update article found at epa.gov/qasstar/newsroom/partnerupdatesprinq2010.html.
Exhibit 1: A skid-rnounted compressor package
recovering casinghead gas at a wellhead (Source:
Hy-Bon Engineering).
Since not all wells respond favorably to reducing casinghead pressure, companies may want to
test a well before purchasing or leasing compression equipment. Testing is performed to
,,, 1
Winter 2010
-------
determine a well's response and ensure that increased productivity is not temporary. Adjacent
wells from the same formation may have different responses to casinghead gas capture, which
also points to the need for testing. Generally, if increases in oil production remain constant after
30 to 45 days, it is appropriate to proceed with implementation. Flow increase and emissions
reductions data collected during testing will provide the means to determine the project's
economics.
Considerations/Limitations
The success of this project—to maximize oil production, minimize emissions, and reduce
downtime—is largely dependent on matching the compressor specifications to the specific
reservoir. Each well has its own unique characteristics, so the compressor needs to be
designed accordingly. Gas volume, discharge line pressure, and specific gravity of the gas
stream are all key factors that need to be considered when designing the compressor for a well
The key limitation to keep to mind is that there is no definite method or rule-of-thumb for
estimating a well's response to casinghead gas capture. This is because it is difficult to predict
what is occurring below in the formation itself. Generally, this project tends to be successful in
wells with water or carbon dioxide floods, typically used in enhanced oil recovery (EOR) where
the produced gas can be re-injected Into the reservoir. Despite this uncertainty, experience
from a vendor shows about 65 percent of oil wells in mature basins respond successfully to
casinghead gas capture.
Skid-mounted compressors usually range
from 10 to 200 horsepower and can be
powered by either electricity or a
combustion engine. The availability of a
power source is the key factor in
determining which option is more viable.
Electric-driven compressors are usually
preferred because of less required
maintenance and because they do not
consume valuable sales gas. If electricity
is not available at a wellhead, then a
beam-mounted compressor may provide
an economic solution (see insert).
The proximity of the compressor to the
wellhead is another factor to consider.
Often a single compressor can be linked
to multiple wells if they are close enough
to each other. If the wells are too far,
then pressure drop can become an issue.
All wells need to be at or about the same
surface pressure, so they can all be
pulled upon equally by the compressor.
Operators trying to save on compressor
costs can link wells that are far apart, but
doing so can keep the compressor from
bringing the nearby wells closer to zero
pressure, losing potential revenue in
recovered gas.
, If1 A artner Update 9
Winter 2010
Beam Gas Compressor™ (BGC™)
• Another option for casinghead gas capture projects
• Utilizes mechanical energy from well's rod pumping
unit as primary energy source
• Single- or double-acting: can compress on both
strokes
• Differential pressure up to 9 compression ratios
• Volumes can be as high as 500 Mcf/day, depending
on 1) pumping unit size, 2) flowline pressure, 3)
formation attributes, and other characteristics.
Exhibit 2: Two Beam Gas Compressors™ each utilizing
the mechanical energy of a pumpjack to pull gas from the
casing and discharge it into a flowline (Source: Permian
Production Equipment, Inc.).
-------
Also, the use of one compressor for multiple wells introduces a dependence on that single unit.
In the case when the compressor breaks or is down for maintenance, operators would either
have to: 1) vent the casinghead gas to the atmosphere from all linked wells to continue oil
production, 2) refrain from venting and have decreased oil production, or 3) use a temporary
compressor for gas capture. Until the original compressor is repaired, the linked wells will not
be able to both reduce emissions and increase the operator's revenue.
Other potential issues to keep in mind before implementing this project are variations in
wellhead flow rate, insufficient oil flow, and the production of liquids from casinghead gas. Most
compressors cannot handle liquid slugs, so design modifications to the gas gathering system
must be made. Examples include the use of drip pots, a scrubber, or a separator.
Costs and Benefits
The main benefit of this project type is the
additional revenue from increased oil
production. The sales of previously
uncollected associated gas and emissions
reductions are important secondary
benefits.
The major costs associated with the
project are 1) equipment costs of the
compressor package and piping, 2)
installation costs, and 3) annual operating
and maintenance (O&M) costs for fuel or
electricity. These costs vary from site to
site and depend on the type and size of
the compressor as well as the piping
distance from well to compressor and
compressor to sales line. Several Natural
Gas STAR Partners have reported success in implementing projects to reduce casinghead gas
pressure on their wells and have reported payback periods of less than one year (see PRO Fact
Sheet links below)
Conclusion
Casinghead gas capture has become an effective way for companies to increase oil production
and recover BTU-rich gas for sales by using a small wellhead compressor or vapor recovery
unit to reduce the pressure buildup in the annular space of an oil well. Adequate testing before
implementation is recommended. This project is a cost-effective alternative to venting, reducing
a significant amount of methane emissions from mature oil-producing wells.
For more information:
PRO Fact Sheet No. 701: Connect Casing to Vapor Recovery Unit.
epa.gov/qasstar/documents/connectcasinqtovaporrecovervunit.pdf
PRO Fact Sheet No. 702: Install Compressors to Capture Casinghead Gas.
epa.gov/qasstar/documents/installcompressors.pdf
McCoy, Charlie, Compressor Gathers Low-Pressure Gas. The American Oil & Gas Reporter. August 2008.
beamgascompressor.com/articles.htm
Richards, Larry and Sidebottom, James. Systems Reduce Casinghead Pressure. The American Oil & Gas Reporter,
May 2005. hv-bon.com/tech%20librarv/pdf/case%20studies/Article-AQGRCasinghead.pdf
tTt , A artner Update 10
Winter 2010
f
Exhibit 3: Flow lines from multiple wells linked to a single
compressor package. Distance is a key consideration
before implementing this method of recovery (Source: Hy-
Bon Engineering).
-------
Prospective Projects Spotlight:
Reducing Supply Pressure in
Pneumatic Systems
Natural Gas STAR Partners have used various methods for reducing pneumatic device
emissions (see insert), and the alternative explored here is to reduce the supply pressure.
Depending on operating parameters and
design of the pneumatic system, the
pneumatic gas supply pressure can range
from 20 pounds per square inch gauge (psig)
to more than 100 psig. Because the supply
pressure has a direct effect on the bleed rate
and fugitive emissions to the atmosphere, this
project idea can have a significant impact on
methane emissions.
Existing Mitigation Opportunities
• Replacement of high bleed devices with low
bleed devices.
• Retrofit of high bleed devices to achieve low
bleed characteristics.
• Converting gas supply to instrument air.
• Converting to electric valve controllers.
• Converting to mechanical control systems.
More information is available at:
www.eDa.aov/aasstar/documents/ll Dneumatics.odf
Background
The basic pneumatic device schematic can be seen below in Exhibit 1. Clean, dry, pressurized
natural gas is regulated to a constant pressure. This gas supply is used both as a signal and a
power supply. A small stream is sent to a device that measures a process condition (liquid
level, gas pressure, flow, temperature). For a 20 psig supply pressure, this device regulates the
pressure of this signal stream (from 3 to 15 psig typically) in proportion to the process condition.
The stream flows to the pneumatic valve controller, where its variable pressure is used to
regulate a valve actuator. The valve actuator may also be connected directly to the pneumatic
gas supply and uses this "power" pneumatic gas to adjust the position of the control valve.
Regulator
100+ psi
Gas
Regulated Gas Supply
20 psi
Weak Signal Bleed
(Continuous)
Weak Pneumatic
Signal (3-15 psi)
Strong Signal Vent
(Intermittent)
Strong
Pneumatic
Signal
Valve Actuator
Control Valve
Process Flow
Pneumatic
Controller
Process
Measurement
Liquid Level
Pressure
Temperature
Flow
Exhibit 1: Basic Pneumatic Device Schematic
NatuiaIGas<\
sra poLumaH nmnn '
Partner Update
Winter 2010
11
-------
Within this control scheme, various factors affect the gas bleed rate to the atmosphere,
especially the control configuration and the supply pressure. Control configuration options are
proportional band, reset, integral, and derivative functions which represent increasing
sophistication in valve responsiveness to the process condition. The supply pressure is the gas
pressure required to exert sufficient force on the diaphragm against a spring to open or close a
valve. For some pneumatic systems, the supply gas pressure setting might be higher than
necessary. The greater the supply pressure, the greater the bleed from the device.
Implementation
Many pneumatic devices operate with medium or high supply pressures (35 psig or greater).
However, it might be possible to lower the supply pressure while maintaining adequate energy
in the gas supply to transmit a process signal and/or actuate a valve. A lower supply pressure is
applicable for processes that can tolerate a slower response and some drift in its set point, such
as a liquid level setting between empty and full.
In some cases, the supply pressure can be lowered by simply adjusting the regulator. In other
cases, it might be necessary to replace equipment since some devices are not designed to
operate at lower supply pressures. In other words, the pressure regulator might not have the
capability to operate at a lower supply pressure. The actuator, as designed for a higher supply
pressure, might not operate sufficiently well with a lower supply pressure. Depending on
individual characteristics of each pneumatic system, it might be necessary to replace the
regulator, re-calibrate the actuator spring, or both.
Methane Savings and Project Economics
Emissions reductions will vary per device and can range from 13 to 131 Mcf per year per
device. Exhibit 2 illustrates achievable reductions for six different devices, including pressure,
liquid level, and temperature controllers. The achievable reductions of implementing this project
opportunity on a facility level will vary according to the total device count.
¦ Average Bleed Rate at
35 psig Supply Pressure
Pressure Controllers I t t
~ Average Bleed Rate at
50.0
45.0
40.0
35.0
S 30.0
-------
13 to 131 thousand cubic feet per device (Mcf/device). Exhibit 3 summarizes an economic
analysis for two different pneumatic device models as examples representing the largest and
smallest gas savings of the six devices shown in Exhibit 2.
The capital costs of implementing this project idea will vary depending on the work required to
modify the pneumatic gas supply, as mentioned in the previous section. For the basic economic
analysis summarized in Exhibit 3, it is assumed that the regulator would have to be replaced.
This was selected as the representative case because it is not as simple as turning a knob to
adjust the pressure setting but is not as complex as re-calibrating the actuator.
PROJECT SUMMARY: REDUCE SUPPLY PRESSURE IN PNEUMATIC SYSTEM
Type of Device
Mallard Control Model 3300
(Pressure Controller)
Fisher C1
(Pressure Controller)
Supply Pressure Reduction
35 psig to 20 psig
35 psig to 20 psig
Annual Operating Hours
8,760
8,760
Incremental Capital &
Installation Costs
$204 1
$204 1
Annual Incremental Labor &
Maintenance Costs
$0
$0
Methane Saved (Mcf per year
per device)
131
13
Gas Price per Mcf
$3
$7
$10
$3
$7
$10
Value of Gas Saved
$394
$920
$1,314
$234
$546
$780
Payback Period in Months
7
3
2
11
5
4
1 Capital cost includes the cost of a new pressure regulator ($62.00) and an assumed 2 hours of labor (at $71 per hour).
Exhibit 3: Summary of Economics for two Representative Single Device Scenarios
The table shows that lowering supply pressure, where applicable, is an activity that pays back in
less than one year, and the benefits compound as the number of affected devices increases.
Conclusion
In some situations it may be possible to reduce the supply pressure in pneumatic devices, which
can achieve significant gas savings by operating existing equipment differently. This project idea
can also complement other Natural Gas STAR practices to reduce emissions from pneumatic
devices when carried out in combination.
BBSA? Winter 2010>d'
-------
Climate Policy Update: Mandatory Reporting of Greenhouse
Gases Rule, Subpart W
On November 8, 2010, Administrator Jackson signed the Greenhouse Gas Mandatory
Reporting Rule for the Petroleum and Natural Gas Systems source category (40 CFR part 98,
subpart W). This mandatory reporting rule requires facilities from segments of the petroleum
and natural gas industry that emit 25,000 metric tons or more of carbon dioxide equivalent per
year, to report carbon dioxide (C02), methane (CH4), and nitrous oxide (N20) emissions, along
with relevant activity data.
Who is affected?
Facilities that emit greater than or equal to the reporting threshold of 25,000 metric tons of
carbon dioxide equivalent will be required to report emissions. Industry segments required to
report include offshore petroleum and natural gas production, onshore petroleum and natural
gas production, onshore natural gas processing, onshore natural gas transmission
compression, underground natural gas storage, liquefied natural gas (LNG) storage, LNG import
and export terminals, and natural gas distribution. Reporting is at the facility level.
What must be reported and how?
The final rule requires petroleum and natural gas facilities to report annual methane (CH4) and
carbon dioxide (C02) emissions from equipment leaks, and venting, and emissions of C02, CH4
and nitrous oxide (N20) from flaring. Emissions from stationary and portable combustion
equipment are to be reported from the onshore petroleum and natural gas production industry
segment. Emissions from stationary combustion equipment are to be reported from the natural
gas distribution industry segment also.
The calculation methodologies used in this rule generally include the use of engineering
estimates, emissions modeling software, and emission factors or when other methods are not
feasible, direct measurement of emissions.
When must emissions be reported?
Data collection under subpart W begins on January 1, 2011, with reports due annually to EPA
with the first report due to EPA by March 31, 2012 covering 2011 emissions. Certain reporters
may use best available monitoring methods (BAMM) for a limited period during the 2011 data
collection year, for some emissions sources, if they meet specific criteria.
Further details on the rule can be found at
www.epa.gov/climatechange/emissions/subpart/w.html
BBSA? Winter 2010>d'
-------
Utah BLM Request for Participation
In an effort to support reducing fugitive methane emissions, Utah BLM is requesting a
participant that would be interested in a project to capture casing-head gas that is released at
the wellhead. In isolated development areas, without access to a pipeline, natural gas from an
oil well may be flared as the preferred alternative. With advances in technology it may be
possible to collect the casing-head gas and compress it at the wellhead so it can be marketed.
The economic feasibility and timely payout generally is dependent on gas quality and quantity.
Please share with us any experiences you may have with capturing casing-head gas,
successful or not. Also, if you have an area that would be a good candidate for a pilot project
please contact:
Mike McKinley
Environmental Scientist/NRS, P.G.
Fluid Minerals Branch
BLM Utah State Office
440 West 200 South, Suite 500
Salt Lake City, UT 84101
email: mike mckinlev@blm.gov
phone: 801-539-4046
fax: 801-539-4261
EPA Helps Launch Global Methane Initiative to Cut Greenhouse Gases
On October 1st, 2010 the new Global Methane Initiative was launched
with support from 38 countries, urging stronger international action to
address near-term climate change. The initiative will build on the
existing structure and success of the Methane to Markets Partnership,
which was launched in 2004, while enhancing and expanding its efforts
and encouraging new financial commitments from developed country partners. The United
States is pledging $50 million over the next five years to the Global Methane Initiative and is
seeking similar pledges from other developed countries to support implementing methane
emissions reduction projects and technologies. EPA estimates that an enhanced global effort to
reduce methane emissions could achieve reductions of more than 1.5 billion metric tons of
carbon dioxide equivalent. For more information about the Global Methane Initiative visit:
http://www.globalmethane.org/gmi/
*
Global
New Natural Gas STAR Partners
Gill Ranch Storage, LLC
The Natural Gas STAR Program is pleased to welcome Gill Ranch
Storage, LLC as an official Partner in the transmission sector of the
Natural Gas STAR Program. Gill Ranch Storage is an underground
natural gas storage facility near Fresno, California and near Pacific Gas GnLRANCH storage
and Electric Company's (PG&E) mainline transmission system. Gill Ranch Storage has the
capacity to provide approximately 20 billion cubic feet (Bcf) of underground natural gas storage.
A Partner Update
Winter 2010
15
-------
It is the farthest south of all independent storage facilities on the PG&E system, offering access
five interconnects. Its parent company is Oregon-based NW Natural Gas Storage, LLC.
UGI Central Penn Gas and UGI Penn Natural Gas
The Natural Gas STAR Program is pleased to welcome both UGI Central Penn Gas and UGI
Penn Natural Gas as official Partners in the distribution sector of the Natural Gas STAR
Program. Both companies are divisions of UGI Utilities Inc., a Partner since 1993.
Cv
mcEtrmLPEi
UGI Central Penn Gas, Inc. distributes natural and liquefied petroleum gas in
Pennsylvania (central and northern regions), Maryland, and Delaware. The
company offers natural gas distribution, transmission, and storage services, as
cEuwLKwve we|| gs se||s pr0pane T^g company formerly known as Penn Fuel Gas, Inc.,
was founded in 1944 and is based in Allentown, Pennsylvania.
Serving approximately 158,000 customers in 13 counties through
Pennsylvania, UGI Penn Natural Gas, Inc. distributes natural in northeastern
and central Pennsylvania as the region's largest natural gas distribution
company. The company sells and services a range of natural gas appliances
and equipment, and its customers utilize the natural gas for space heating,
water heating, cooking, and cooling. The company, formerly known as PG Energy, Inc., was
founded in 1854 and is headquartered in Wilkes-Barre, Pennsylvania.
New Global Methane Initiative Member Countries
Nicaragua
Nicaragua was welcomed into GMI on 30 September 2010. Nicaragua has opportunities for
methane capture and reuse projects in the areas of agriculture and landfills, and will be joining
those respective subcommittees. In Nicaragua, there is a huge
potential to generate electricity using methane produced by
reserves of biomass (i.e., vegetable residues from food and
agricultural products processing such as sugar) as well as the
761,000 tons per day generation of urban organic wastes.
Nicaragua will also contribute its experience in small biogeneration
in the agro-food industry and municipal landfills.
Turkey
Turkey was welcomed into GMI on 30 September 2010 and will
participate in the Coal Mines, Landfills, and Oil and Gas
Subcommittees. Based on data in EPA's Global Anthropogenic
Emissions of Non-C02 Greenhouse Gases report, in 2010, Turkey's
estimated anthropogenic methane emissions ranked 12th in the
world. Oil and natural gas systems represent half of Turkey's
anthropogenic methane emissions—57.20 MMTC02E—and an
additional 26 percent (28.85 MMTC02E) come from agriculture (manure management), coal
mining, landfills, and wastewater. In particular, Turkey expressed interest in developing clean
energy opportunities for use of methane captured from its large coal reserves.
o
Hi ^ ip Partner Update
^^^47 Winter 2010
-------
Upcoming Events
Stay tuned for more upcoming Natural Gas STAR and Global Methane Initiative
events. Additional workshops in 2011 will be announced soon!
Program Managers
Scott Bartos (bartos.scott@epa.gov)
Phone:(202) 343-9167
Jerome Blackman (blackman.jerome@epa.gov)
(202) 343-9630
Carev Bvlin (bylin.carey@epa.gov)
(202) 343-9669
Roger Fernandez (fernandez.roger@epa.gov)
(202) 343-9386
Suzie Waltzer (waltzer.suzanne@epa.gov)
(202) 343-9544
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 Scott Bartos.
Global
Methane Initiative
Natural Gas STAR Contacts
Partner Update
Winter 2010
17
------- |