|
|
THE EPA NATURAL GAS STAR PROGRAM |
| PTTC Home | Solutions From the Field |
Based on a Producers Technology Transfer Workshop on August 30, 2005 in Casper, Wyoming sponsored by Devon Energy Corporation.
The Natural Gas STAR Program is a flexible, voluntary program between the EPA
and the oil and natural gas industry and is designed to cost effectively reduce
methane emissions from natural gas operations. The program has one hundred and
eleven industry partners. Twenty two of these partners own 62 percent of the
nation's transmission assets; forty five partners own 60 percent of the
distribution assets; thirty two partners own 51 percent of the production
assets; and twelve partners own 63 percent of the producing assets. It can be
seen that the major part of the USA's gas industry infrastructure is covered by
the program. All but two of the top twenty five producers are represented.
Methane represents 8 percent of the US greenhouse gas emissions. Carbon dioxide,
at 85 percent, represents the bulk of the remainder. However, methane is 23
times more effective as a greenhouse gas than carbon dioxide. Oil and natural
gas systems at 26 percent of the total, are the biggest contributor to methane
emissions. Other major sources of methane are landfills (24 percent), enteric
fermentation (21 percent) and coal (10 percent). According to a 2005 EPA Report,
oil and gas production generated 148 Bcf in methane emission; transmission and
storage, 101 Bcf; distribution, 68 Bcf; and processing, 36 Bcf. Partners in the
Natural Gas STAR Program have achieved significant successes with a 403 Bcf
reduction in methane emissions since 1990, increasing revenue by over $1
billion.
The program has identified 3 best management practices (BMPs) that offer the
greatest opportunity to reduce methane emissions. These are:
1: Identify and replace high bleed pneumatic devices.
2: Install flash tank separators on glycol dehydrators.
3: Participate in Partner Reported Opportunities (PROs) - 83 percent of
production sector reductions came from PROs.
The Gas STAR program has identified 42 PROs that are applicable to the
production sector. The top ten PROs are responsible for over two thirds of PRO
emission reductions.
With the increased evidence of global warming, it is imperative to reduce greenhouse gas emissions. Strong natural gas prices make it increasingly profitable to improve revenues by the reduction of lost methane gas. This meeting addressed some of the methodologies used.
Gas STAR, Methane emissions, EPA, Glycol dehydrators, Desiccant dehydrators, Flash tank separators, Green completions, Vapor recovery, Optical imaging, BMP Management System
EPA Natural Gas STAR Program:
Roger Fernandez
Devon Energy Partner Experience in Methane Emission Mitigation:
Ron Truelove
Reduced Emission Completions (Green Completions):
Don Robinson
Natural Gas Star On-line Resources:
Ron Truelove
Natural Gas Dehydration:
Ed Hauswald
Installing Vapor Recovery Units to Reduce Methane Losses:
Larry Richards
Directed Inspection and Maintenance and Optical Imaging:
Don Robinson and Brad Risser
(FLIR)
Reviews of Presentations
EPA Natural Gas STAR Program—See Bottom Line.
Devon Energy Partner Experience in Methane Emission
Mitigation
Devon Energy became a Gas STAR partner on July 21, 2003. There was a signing
ceremony with the CEO, Larry Nicholls, to show the importance of this event and
to signal that it was supported by upper management.
Devon stressed the principles for a successful program:
Devon has been very active in program participation since 2003. Its projects
include writing an SPE Paper on the optimization of separator pressure to reduce
methane emission; producing a monthly STAR Newsletter; sponsoring workshops and
participating in a leak detection survey at its Bridgeport Plant. Devon's
monthly STAR newsletter is currently posted on the EPA website. It contains a
PRO fact sheet and has links to lessons learned from the EPA Gas STAR website.
Devon's accomplishments include over 13.2 Bcf reduction in methane emissions
since 1990. This represents over $52 million in revenue gains.
Devon discussed reduced emission completions (RECs) in the Fort Worth Basin.
Devon estimates that it saves $53,000 per well using these techniques and plans
to extend the program to the Washakie Basin of Wyoming in August of 2005.
Reduced Emission Completions (Green Completions)
According to a GRI Study, 45.5 Bcf of natural gas is lost
annually due to well completions and workovers. When gas wells are drilled, a
final step before producing the natural gas to a sales line is to "clean-up" the
wellbore and reservoir immediately surrounding the well. Traditionally, this
well completion step involves discharging the well to open pits or tankage where
sands, fluids and reservoir fluids are collected for disposal and the produced
natural gas is vented to the atmosphere. Flaring is preferably to venting, as
methane has 23 times more greenhouse effect than CO2.
Partners reported using a "green completion" method in which equipment is
brought to the site to clean up the gas sufficiently for delivery to sales. This
additional equipment may include considerably more tankage, special
gas-liquid-sand separator traps, and portable gas dehydration. In addition to
reducing methane emissions, green completions produce an immediate revenue
stream with the produced natural gas and gas liquids, less solid waste and water
pollution, and a safer operating practice.
The key to this process is having an available sales pipeline. Wyoming has just
passed legislation requiring green completions in certain heavily drilled areas
(Pinedale and Jonah). Coalbed methane usually has too low a flow rate to benefit
from this technique.
Partners reported recovering an average of 53 percent of the total gas produced
during well completions and workovers. They estimate an average of 3,000 Mcf of
gas and 1-580 bbl of condensate can be recovered from each clean-up. BP's
specific experience was discussed. They made a capital investment of $1.4
million on a portable three phase separator, sand traps and tanks, and used
green completions on 106 wells. They reported 350 MMcf of natural gas and 6,700
bbl of condensate recovered per year. The total value of this product was
approximately $840,000 per year and the payback time is slightly over two years.
A pilot project by Weatherford in Fruitland Coal near Durango was also cited.
Weatherford used portable equipment on three wells and captured 2 MMcf of gas
which was sold by the client.
Natural Gas Star On-line Resources
Devon Energy has developed a database to track future methane
reduction activities. It is called the Gas STAR Online BMP Management System and
will be released on the EPA Gas STAR Website as soon as the EPA lawyers approve.
The software has been developed by Brian Boyer of COMM Engineering and Dr. Gerry
Knapp of Louisiana State University. The source code will be available for
modification by users. The code is written in ASP.Net and is designed to be
deployed on servers. It can be modified using any of the major programming
languages. A release of this software on CD is planned for the Producers
Technology Transfer Workshop on October 26, 2005 in Houston, Texas.
Natural Gas Dehydration
There are approximately 30,000 high-pressure onshore gas wells
producing 4 Tcf of natural gas in the USA annually. About 700 of these wells
have conventional glycol dehydrators, emitting an estimated 1 Bcf of methane per
year to the atmosphere. Glycol dehydrators vent methane, volatile organic
compounds (VOCs), and hazardous air pollutants (HAPs) to the atmosphere, and
also bleed natural gas to the atmosphere from pneumatic control devices. Natural
gas STAR partners found that replacing glycol dehydrators with desiccant
dehydrators reduces methane, VOC and HAP emissions by 99 percent and also
reduces operating and maintenance costs. Economic analysis demonstrates that
replacing a glycol dehydrator processing 1 MMcfd can save up to $4,403 per year
in fuel gas, vented gas, and operational and maintenance cost, and can reduce
methane emissions by 564 Mcf per year. This assumes a $3 per Mcf price of gas.
Another subject discussed was the optimization of glycol circulation and the
installation of flash tank separators in glycol dehydrators. There are
approximately 38,000 glycol dehydration systems in the natural gas production
sector emitting an estimated 22Bcf of methane per year into the atmosphere. Most
dehydration systems use triethylene glycol (TEG) as the absorbent fluid to
remove water from natural gas. As TEG absorbs water, it also absorbs methane,
VOCs and HAPS. As TEG is regenerated through heating in a reboiler, absorbed
methane, VOCs and HAPs are vented to the atmosphere. The authors discuss
optimizing the TEG circulation and installing flash tank separators to minimize
the venting of these gases.
The option of replacing the energy-exchange pump on the TEG line with an
electric motor driven pump was also mentioned. The can reduce the gas entrained
in the TEG by a much as two thirds.
An economic analysis of these methods was made. It was estimated that optimizing
circulation rates had negligible costs and could result in emission savings of
130 -13,133 Mcf per year. Payback is immediate. Installing a flash tank costs
$5000 -$10,000 and would save 336-7,098 Mcf per year. Payback is estimated at
5-17 months. Installing an electric pump costs from $4,200 to $23,400 with
$3,600 annual O & M costs. Savings are estimated at 360-36,000 Mcf per year,
with a payback between less than 2 months to several years.
Installing Vapor Recovery Units to Reduce Methane
Losses
It is estimated that 9 Bcf of methane is lost per year from
storage tanks. This represents 6 percent of methane emissions from the natural
gas and oil production sector. Historically, hydrocarbon vapor recovery from
many oilfield production facilities' oil and water tanks was considered
uneconomical because of relatively low vapor volumes and low gas prices. In
addition, compressor based vapor recovery systems involved high capital
expenditure and operating costs. The presentation discussed various methods of
vapor recovery.
Vapor recovery units can capture up to 95 percent of hydrocarbon vapors vented
from tanks and these vapors have a higher Btu content than pipeline quality
natural gas. Conventional vapor recovery units (VRUs) used a rotary compressor
to suck vapors out of atmospheric pressure storage tanks and require electrical
power or an engine. Venturi ejector vapor recovery units (EVRUs) and vapor jets
use venturi jet injectors in place of rotary compressors and do not contain any
moving parts. However, the EVRU does need a source of high pressure gas and an
intermediate pressure system. Vapor jets need a high pressure water motive. The
vapor jet system is patented by Hy-Bon Engineering.
The criteria for VRU location is a steady source and sufficient quantity of
losses. Possible locations include crude oil stock tanks, flash tanks, heater/treaters,
water skimmer venters, and gas pneumatic controllers and vents. VRUs also
require an outlet for the recovered gas, such as a low pressure gas pipeline,
compressor suction or on-site fuel system.
The first step in installing a VRU is to estimate losses. These can be estimated
either by using charts (± 50 percent), or using the E & P Tank Model (± 20
percent), which is available from the API for $600. Alternatively, losses can be
measured using a recording manometer and well tester, or an ultrasonic meter.
Then, an estimate should be made as to the value of the recovered gases.
Examples for industry experience from ChevronTexaco and Devon Energy were given.
ChevronTexaco installed eight VRUs at crude oil stock tanks in 1996. Methane
loss reduction was estimated at 21,900 Mcf/unit per year, for an approximate
savings per unit of $43,800. Capital costs per unit were about $30,000, so the
payback was less than one year. Devon has employed a vapor jet system and
recovered more than 55 MMcf of gas from oil stock tanks over a five year period.
Revenue was about $91,000, with capital costs of $25,000 and operating cost of
$0.40 per Mcf of gas recovered. This paid back the investment in less than two
years.
The general lesson learned was that VRUs can be highly cost effective in most general applications.
Directed Inspection and Maintenance (DI&M) and
Optical Imaging
The production sector, at 148 Bcf, is responsible for the largest
portion of methane emissions, but it also has several large sources that can be
targeted for reduction. This presentation gave a detailed review of implementing
a Directed Inspection and Maintenance (DI&M) program at production sites to
detect, measure, prioritize and repairs leaks to reduce these emissions. There
was also a demonstration of the use of optical imaging technology with FLIR
Systems infrared imaging technology.
Valves of various kinds contribute to 33.4 percent of emissions by equipment
type. They are followed by connectors at 24.4 percent, compressor seals at 23.4
percent and open ended lines at 11.1 percent. The problem with detecting these
leaks is that they are invisible, unregulated and go unnoticed. In the
experience of the author, the cost of a survey to find these leaks will pay for
itself in one year. The process for implementing a DI&M was explained. The steps
included:
Screening methods for leaks use soap bubble screening; electronic screening (sniffer),
toxic vapor analyzer (TVA), organic vapor analyzer (OVA), ultra sound leak
detection, acoustic leak detection, and optical leak imaging. To evaluate the
volume of leaks, high volume samplers, toxic vapor analyzers, and rotameters
were suggested.
A real-time demonstration of leak imaging was given by FLIR Systems, showing
that leaks could be quickly identified and repaired. Hundreds of components
could be screened per hour and it was also possible to screen inaccessible areas
by simply viewing them. It was emphasized that open-ended lines, compressor
seals and valves represented less than 3 percent of components, but contributed
to more than 60 percent of emissions.
Two partner case histories were discussed. In one case, a leaking cylinder head
was tightened, reducing methane emissions from 64,000 Mcf per year to 3,300 Mcf/year.
The repair required 9 man-hours of labor; the value of gas saved at $3 per Mcf
was $182,100 per year. In the second review case, a one-inch pressure release
valve was emitting almost 36,774 Mcf per year. The repair cost was $125 in
materials and five man-hours of labor. The value of gas saved was $110,300 per
year at $3 per Mcf.
A complete review of the meeting with PowerPoint slides is available from the
EPA Gas STAR website at
www.epa.gov/gasstar.
James Lea
Roger Fernandez
EPA
Washington, DC
202.343.9386
Fernandez.roger@epamail.epa.gov
Ron Truelove
Devon Energy
Oklahoma City, OK
405.552.4516
rontruelove@dvn.com
Don Robinson
ICF Consulting
Fairfax, VA
703.218.2512
drobinson@icfconsulting.com
Ed Hauswald
ICF Consulting
Fairfax, VA
703.934.3115
ehauswald@icfconsulting.com
Larry Richards
Hy-Bon Engineering
Midland, TX
432.697.2292
lrichards@hy-bon.com
Dave Valley
FLIR Systems
North Billerica, MA
866.477.3687
david.valley@flir.com
Dr Gerry Knapp
Louisiana State University
Baton Rouge, LA
225.578.5374
gknapp@lsu.edu
Brian Boyer
COMM Engineering
Lafayette, LA
337.237.4373
brian@commengineering.com
Disclaimer: No specific application of products or services is endorsed by PTTC. Reasonable steps are taken to ensure the reliability of sources for information that PTTC disseminates; individuals and institutions are solely responsible for the consequences of its use.
The not-for-profit Petroleum Technology Transfer Council is funded primarily by the US Department of Energy’s Office of Fossil Energy, with additional funding from universities, state geological surveys, several state governments, and industry donations.
Petroleum Technology Transfer Council, 16010 Barkers Point Lane, Ste 220, Houston, TX 77079
toll-free 1-888-THE-PTTC; fax 281-921-1723; Email hq@pttc.org; web
www.pttc.org
| PTTC Home | Solutions From the Field |
|
We encourage your comments, please send us email at: hq@pttc.org. Copyright © 2005 Petroleum Technology Transfer Council |