United States
Environmental Protection
Agency
Air and Radiation
(6202 J)
430-R-97-012
December 1997
Technical and Economic
Assessment of Potential to
Upgrade Gob Gas to Pipeline
Quality
\ETHAN
OUTREACH
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C O A
METHANE
OUTREACH
P R O C R A M
Technical and Economic Assessment of
Potential to Upgrade Gob Gas
to Pipeline Quality
Coalbed Methane Outreach Program
Atmospheric Pollution Prevention Division
U.S. Environmental Protection Agency
December 1997
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DISCLAIMER
Legal Notice. This report was prepared for the U.S. Environmental Protection Agency (EPA).
The EPA does not:
(a) Make any warranty or representation, expressed or implied, with respect to the
accuracy, completeness, or usefulness of the information contained in this report, or that
the use of any apparatus, method, or process disclosed in this report may not infringe
upon privately owned rights; or
(b) Assume any liability with respect to the use of, or damages resulting from the use of,
any information, apparatus, method, or process disclosed in this report.
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ACKNOWLEDGMENTS
This report was prepared under Environmental Protection Agency (EPA) Contract 68-W5-0017
by Alternative Energy Development, Inc. (AED) and the University of Utah (U of U). EPA would
like to thank the Department of Energy (DOE) and representatives of the industrial firms that
supplied the technical and cost data that were used in the document. Additionally, EPA would
like to thank the authors of papers that were cited herein: Babcock, et al; D'Amico; Fisher; and
Shirley, et al. The Agency also thanks the peer reviewers whose comments have strengthened
this report.
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CONTENTS
FIGURES i
TABLES i
MEASURES AND ACRONYMS ii
1.0 INTRODUCTION AND BACKGROUND 1
2.0 EVALUATION OF GOB GAS ENRICHMENT TECHNOLOGIES 3
2.1 Integrated Approach 4
2.2 Cryogenics Process 4
2.3 Pressure Swing Adsorption (PSA) 5
2.4 Selective Absorption 6
2.5 Summary of Nitrogen Rejection Process Characteristics 7
2.6 Other Processes 7
2.6.1 Oxygen Removal 8
2.6.2 Carbon Dioxide Removal 8
2.6.3 Water Vapor Removal 8
2.6.4 Hydrogen Sulfide Removal 8
2.7 Technical Assessment 9
2.7.1 Cryogenics Process 9
2.7.2 Selective Absorption 9
2.7.3 Pressure Swing Adsorption 9
2.7.4 General 10
2.8 Emerging Technologies 10
2.8.1 Alternative PSA Technologies 10
2.8.2 An Alternative Absorption Technology 11
2.9 Technical Assessment Summary 11
2.10 Outlook 12
3.0 COST ANALYSIS 14
3.1 Objective 14
3.2 Cost Summary 14
3.3 Plant Size Selection 14
3.4 Cost Data and Engineering Estimates 16
3.4.1 Compression Requirements 16
3.4.2 Methane Recovery '. 17
3.4.3 Fuel Requirements 17
3.4.4 Estimation of Error 17
3.5 Analysis Format 18
3.6 Analysis of Results 19
3.6.1 Cost Sensitivity to Gas Flow Rate 19
3.6.2 Cost Sensitivity to Methane Content of the Feed Gas 20
3.6.3 One Plant versus Two 21
3.6.4 Cash Flow Analyses 23
3.6.5 Future Cost Trends 23
3.6.6 Cost Study Conclusions 23
4.0 CONCLUSIONS 25
4.1 Commercial Opportunities 25
4.2 System Suppliers Willing to Demonstrate 25
4.3 Technical Concerns 25
4.4 Cost Effective Projects 25
4.5 Effects of Natural Gas Prices on Profitability 26
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4.6 Market Incentives 26
4.7 Financial Assistance: State, Local, and Federal 27
4.8 CMOP Assistance 28
APPENDICES
A Assumptions Used in the Cost Analyses
B Cost Analysis
B.1 Unit Cost Analysis - Tables 1.1 through 1.20
B.2 Cash Flow Statements - Tables 2.1 through 2.3
C References
D Contact Information
E Technical Evaluations of Enrichment Processes
F Information about the EPA Coalbed Methane Outreach Program
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FIGURES
Figure 1 Low-end Costs versus Feed Gas Flow Rate
Figure 2 Low-end Costs versus Methane Concentrations in the Feed Gas
Figure 3 High-end Costs versus Feed Gas Flow Rates
Figure 4 High-end Costs versus Methane Concentrations in the Feed Gas
Figure 5 Cost Comparison for Piped Gob Gas to a 6 mmscfd Plant versus Two 3 mmscfd
Plants
TABLES
Table 1 Typical Gob Gas Composition on a Volume Basis and Required Pipeline
Composition
Table 2 Summary of Nitrogen Rejection Enrichment Systems
Table 3 Summary of the Low and High Gob Gas Enrichment Costs
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MEASURES AND ACRONYMS
MEASURES:
Btu
F
hp
hr
mmBtu
mmscfd
mscfd
ppm
psi
psia
psig
ppmv
scf
British thermal units
Fahrenheit, degrees
Horsepower
Hour
Million British thermal units
Million standard cubic feet per day
Thousand standard cubic feet per day
Parts per million
Pounds per square inch
Pounds per square inch, absolute
Pounds per square inch, gauge
Parts per million (by volume)
Standard cubic feet
ACRONYMS:
AED
AET
BACT
CMOP
CRF
DOE
EPA
GRI
GWP
NRU
PSA
REI
UofU
Alternative Energy Development, Inc.
Advanced Extraction Technologies, Inc.
Best Available Control Technology
Coalbed Methane Outreach Program
Capital Recovery Factor
U.S. Department of Energy
U.S. Environmental Protection Agency
Gas Research Institute
Global Warming Potential
Nitrogen Rejection Unit
Pressure Swing Adsorption
Resource Enterprises, Inc.
University of Utah
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1.0 INTRODUCTION AND BACKGROUND
Coal mines venting methane to the atmosphere are responsible for approximately eight percent
of global methane emissions (EPA, 1993). Methane, in turn, is 21 times as effective as carbon
dioxide in trapping heat in the atmosphere and accounts for 20 percent of the greenhouse
effect that is causing global climate change. Much of the methane emissions from active coal
mines comes from mine ventilation exhaust shafts, but the methane concentration is so minute
(less than one percent) that it is rarely economically recoverable given current technologies.
Gas from gob wells, the other major source at many active longwall mining operations,
however, is available at methane concentrations from about 30 percent to over 90 percent. In
this range of concentrations gob gas may become a valuable fuel for such uses as generating
power in gas turbines or internal combustion engines, or for direct firing in industrial furnaces or
boilers. Another potential use that seems well within reach is injection into natural gas pipelines
after refinement to required gas quality specifications (typically to 97 percent methane by
volume).
Because of a high level of interest among coal mine owners and others interested in refining
(enriching) gob gas, the U.S. Department of Energy's Morgantown Energy Technology Center
(DOE) sponsored and partially funded a study entitled "Commercialization of Waste Gob Gas
and Methane Produced in Conjunction with Coal Mining Operations" (referred to as the DOE
Report in this assessment). Resource Enterprises, Incorporated (REI), who co-funded the
study, had a team which included the University of Utah (U of U) and Heredy Consultants. The
study incorporated both original assessments of the subject and findings from previous studies,
notably papers published by the Gas Research Institute (GRI). DOE published the final report
from this research effort in 1993. It covered both the potential for conversion of gob gas to
useful chemicals and enrichment to pipeline quality. The major conclusions of the report
included the following:
• With technology that is already available, it is relatively straightforward to enrich a gas
stream that contains only one contaminant. Gob gas, however, has four contaminants
(nitrogen, oxygen, carbon dioxide, and water vapor) each of which may be separated
from the methane using a combination of existing processes of varying degrees of
complexity and compatibility. Designers of integrated clean-up processes therefore
must use care to achieve operating and cost effectiveness as well as safety in a
combined, or integrated, system.
• The nitrogen rejection unit (NRU) is the most critical and expensive component of any
enrichment system. Three NRU technologies are potentially suitable: 1) cryogenics, 2)
selective absorption, and 3) pressure swing adsorption (PSA). The cryogenics process
is very sensitive to the presence of impurities and, therefore, may not be appropriate for
a gob gas application (unless an improved system design is able to overcome such
limitations). Both selective absorption and PSA are acceptable. Methane recoveries in
both processes are similar and capital and operating costs are comparable. The
selective absorption and PSA processes, however, handle oxygen differently. The
selective absorption system requires oxygen removal prior to nitrogen rejection,
whereas PSA removes most of the oxygen in the NRU. Thus an integrated process
involving PSA would be less complex. The design of a PSA system must include
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Technical and Economic Assessment of Potential to
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safeguards to ensure that methane/oxygen mixtures passing through the explosive
range are handled properly.
Since the publication of the DOE Report, technical advances claimed by system vendors have
generated interest with mine operators wanting to sell their gob gas to natural gas pipelines.
These mine operators require an unbiased assessment of the potential to undertake enrichment
projects based on proven technologies at their mines.
The purpose of this report is to reopen the 1993 review of integrated gob gas enrichment
technology to determine which, if any, systems on the market are ready for implementation at
mine sites at reasonable costs. This updated review examines average costs that projects
would incur in a typical mine setting for a variety of feed gas qualities and daily flows. It also
begins the process of evaluating promising technologies that have not yet been proven in
commercial field trials.
This review found evidence that gob gas enrichment has made progress during the past three
years. Suppliers of all three nitrogen rejection technologies affirm that a gob gas enrichment
plant is technically feasible and free of unacceptable risks. Most suppliers are ready to make
firm proposals for integrated enrichment plants. Although there is still no commercially
available integrated facility enriching gob gas, mine operators and system suppliers are working
on specific project applications, and there may soon be an operating plant. Full implementation
is not yet a reality because nitrogen rejection techniques are still quite new, and mine operators
have become interested only recently in using the methane in gob gas. Most of the cost
evaluations for this report were performed in 1995. Since that time, Shirley, et al (1997)
reported on a demonstration of a nitrogen rejection operation from gob gas. This report cites
findings from this demonstration.
Another delaying factor in commercialization of gob gas enrichment has been the price of
natural gas. At today's low gas prices, costs of upgrade plants may be favorable for gas
sources above 5 mmscfd with methane contents at 80 percent or above. Smaller plants with
lower percentages of methane tend not to be cost-effective, but economic results are quite site-
specific. This report analyzed a range of cases using two very simple models. The analytical
software used in this report is available from the EPA's Coalbed Methane Outreach Program
(CMOP) (see Appendix F for contact information). Mine operators can use the models to
assess whether gas enrichment would be cost-effective in their own economic situations and
whether such projects could generate sufficient cash flow to attract capital investment.
Section 2 of this report presents a technical evaluation of available gob gas enrichment
technologies. Section 3 discusses capital and operating costs for enriching gob gas sources
over a range of flow rates and methane contents and presents three hypothetical project cash
flow analyses that demonstrate favorable returns on investment. Section 4 summarizes the
report's conclusions. Finally, the appendices contain cost analysis details, references, contact
information, and a research report on a technical evaluation of gob gas enrichment performed
by the Chemical and Fuels Engineering Department at the University of Utah.
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2.0 EVALUATION OF GOB GAS ENRICHMENT TECHNOLOGIES
Gob gas compositions vary widely from mine to mine, well to well, and over time. Gob gas
containing as little as 50 percent methane is at the low end of the range in which upgrading
could be economically practical; while gas containing over 90 percent methane requires much
less cleanup and is more valuable. From a practical standpoint, most gob gas enrichment
• projects will have feed gas compositions in the ranges shown in Table 1, taken from the DOE
Report. Typical pipeline requirements for enriched, or "sales gas," shown in the table are
representative of specifications that vary from one pipeline company to another. It is the
function of the enrichment plant to convert gob gas to a consistent product that meets pipeline
specifications. If the plant operator were to encounter a pipeline that would accept more lenient
specifications, the effect on the plant's capital cost may be significant.
Constituent
Oxygen
Nitrogen
Carbon Dioxide
Methane
Water Vapor
Gob Gas
(Range)
3 percent (2-6)
16 percent (9-26)
3 percent (3-9)
78 percent (65-85)
Saturated
Pipeline Specification
(Typical)
10 ppm
3 percent max.
3 percent max.
97 percent
7 Ibs/mmscf
Table 1: Typical Gob Gas Composition on a Volume Basis and Required Pipeline Composition
(DOE, 1993)
Coal mine operators have three other options, besides enrichment, to bring their gob gas up to
pipeline quality. First, they may invest in techniques designed to improve recovery so that the
gob gas maintains the highest possible quality standard. Techniques include engineering
designs that optimize gob well and borehole configurations and installation of monitoring
systems. The enrichment step would probably come next and could be followed by blending
with high quality methane if available. A final option is spiking with higher hydrocarbon gases
such as propane (if allowed by the receiving pipeline). Blending and spiking may be most
useful when operators encounter gob gas flows that consistently contain 90 percent methane or
higher.
EPA prepared a user-friendly computer program that helps gas project developers to identify
cost-effective combinations of the various upgrade options. Copies of the program, which are
available from CMOP, allow the user to input case specific operating and market parameters.
The program displays the approximate unit cost of optimum and alternate configurations.
Those who wish more information on these techniques or want to obtain a copy of the model
can contact CMOP (see Appendix F).
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Technical and Economic Assessment of Potential to
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2.1 Integrated Approach
An integrated approach simply refers to an enrichment plant that removes all gas contaminants
with a series of connected processes at one location. It is possible to design various integrated
approaches for gob gas enrichment, but several design challenges confront system suppliers.
Pipeline customers require that sales gas contain no more than three percent non-
hydrocarbons by volume, and their oxygen requirements are especially stringent. Two gob gas
impurities, carbon dioxide and water vapor, are easily removed to pipeline specifications using
existing commercial technologies. Since nitrogen removal from methane is the most difficult
separation technically, and the most expensive, an effective nitrogen rejection process will be
critical for any integrated clean-up system. Technologies for nitrogen rejection as a single
contaminant, at this scale, are commercially available and employed. But the presence of
oxygen in the gob gas complicates some of the nitrogen rejection technologies. The final
challenge is to effectively address the compositional and flow rate variability of gob gas.
Results of the recent demonstration project (Shirley, et al, 1997), emphasize this very aspect
and appear later in this report.
The 1993 DOE report described three available nitrogen rejection techniques (i.e. cryogenics,
pressure swing adsorption, and selective absorption) and the status of system supplier efforts
to adapt them to gob gas. Investigators for this (current) report re-contacted all firms that
supplied information for the earlier report and contacted (known) new suppliers that are also
developing nitrogen rejection systems. The research did not uncover any new suppliers that
are ready to sell and guarantee full-scale nitrogen rejection systems. Some of the interviews
covered a few small firms that are in the process of bringing systems to the market but that are
in need of more development work. Information on these firms appears in Section 2.8 -
Emerging Technologies, below.
During the writing of this report, U of U researchers found potential anomalies in some vendor
approaches to integrated plant design. At that point, U of U undertook a technical assessment
of each of the three technologies to determine if gob gas enrichment is feasible operating under
field conditions. The assessment involved computer simulations of material and energy
balances for various gas flow rates and qualities in each system. Section 2.7 contains
summary results of that work. Detailed results of this study are presented in Appendix E.
Sections 2.2, 2.3, 2.4, and 2.5 are descriptions and commercial summaries of the three NRU
technologies and a summary of their differences. Section 2.6 discusses process components
that may remove the three other contaminants: oxygen, carbon dioxide, and water.
Technical and cost information for the evaluations came from records previously gathered by U
of U for DOE and other work from Gas Research Institute (GRI) reports and from potential
suppliers through telephone and fax communications.
2.2 Cryogenics Process
The cryogenics process uses a series of heat exchangers to liquefy the high pressure feed gas
stream. The process then flashes the mixture. A nitrogen-rich stream vents from a distillation
separator, leaving the methane-rich stream. The cryogenics process recovers about 98
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Technical and Economic Assessment of Potential to
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percent of the methane, the highest rate of the three nitrogen rejection alternatives evaluated.
Large-scale cryogenic plants have become a standard and very reliable method of rejecting
nitrogen from large gas streams. Two small engineering companies in Houston, TX have
offered small-scale cryogenic nitrogen rejection plants (i.e. with inlet flow rates in the range of 2-
10 million standard cubic feet per day). They are Darnell Engineering1 and Schedule A (see
contact information in Appendix D). Designs from these two companies differ only in minor
respects. Each has built systems that operate successfully in the field on substandard natural
gas where nitrogen is the only contaminant that is in need of removal. They often upgrade gas
with methane content as low as 30 percent. Another company, BCCK Engineering, Inc. in
Midland, TX also offers a gob gas upgrade cryogenic system. BCCK participated in a small
scale demonstration that yielded some positive results and is currently (December 1997)
starting up a large scale plant.
Although the size of the gob gas market is at least two orders of magnitude smaller than their
primary (low-grade natural gas) market, these firms indicate interest in it because they feel the
cryogenics NRU is well suited to gob gas. The process may accommodate wide quality
fluctuations and, because of an excellent turndown ratio, may handle changes in mass flow as
well.
Interviews conducted for this report indicated that most of the oxygen removal may be
accomplished in the cryogenic NRU itself, and it may not be necessary to employ a separate
deoxygenation step. In response to the DOE Report's caution that even small amounts of
oxygen in the feed gas would disable a cryogenic process, one of the suppliers showed little
concern because that firm processed gasses containing some oxygen without first passing
them through deoxygenation. U of U simulations (Appendix E), however, found that it may not
be possible to remove oxygen as effectively. Flammability may also be of concern if oxygen is
not removed up front. In any case, the supplier would prefer to conduct gob gas field trials
initially where there is little or no oxygen in the feed. These companies feel confident that there
are no problems enriching gob gas with cryogenics (e.g. safety concerns or the presence of
contaminants) that cannot be overcome with proper design. In fact, BCCK is demonstrating its
confidence by going forward with the full scale gob gas enrichment project currently undergoing
startup.
2.3 Pressure Swing Adsorption (PSA)
In most PSA NRU systems, wide-pore carbon molecular sieves selectively adsorb nitrogen and
methane at different rates in an equilibrium condition. In the gob gas stream containing a
mixture of nitrogen and methane, methane is preferentially adsorbed during each pressurization
cycle. The process recycles methane-rich gas so that methane proportions increase with each
cycle. PSA recovers up to 95 percent of available methane and may operate on a continuous
basis with minimal on-site attention. PSA systems have excellent turndown capability so they
are able to operate effectively with gas flowing at a fraction of rated capacity.
1 The information used for Darnell Engineering in this report is over two years old. EPA was not able to reach them
for further comment.
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Technical and Economic Assessment of Potential to
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This study identified three firms that could offer a molecular sieve PSA system to enrich gob
gas. Two of these, UOP from Houston, TX and Nitrotec Engineering based in Houston, TX, are
presently offering commercial systems and supplied some engineering and cost information.
BOC Group from Murray Hill, NJ recently discussed a PSA process demonstration at two
different scales (Shirley, et al, 1997). This report provides some details of this paper. Gas
Separation Technology in Colorado is developing another PSA process that is not yet
commercially available (see Section 2.8). It is conceptually different from the other PSA
processes as it uses naturally occurring zeolite instead of wide-pore carbon molecular sieves.
The UOP and Nitrotec PSA processes are similar except for some differences in the
pressurization and evacuation steps and several other plant details. There are hundreds of
PSA units operating in the field, only a few of which reject nitrogen, and those are employed in
substandard natural gas fields where nitrogen is the sole contaminant. Because PSA plants
may run with little on-site operator attention, monitoring from remote locations is especially
practical. Technical details and cost estimates changed very little since 1993.
The two manufacturers currently offer to build commercial scale integrated gob gas enrichment
facilities for interested mine ov/ners without further research or field trials. Some gob gas
projects may be cost-effective now, and many more will be if natural gas prices were to rise
even slightly. They feel that PSA facilities will not present unusual risks because no change of
phase takes place (e.g. gas to liquid, liquid to solid, etc.) and the process is very flexible with
respect to changes in gas quality and flow rates. PSA suppliers see risk potential, not on the
plant side, but on the "mine side" (i.e. the ability of the mine operator to maintain gob gas feed
streams within practical limits without disrupting mine operations). They hope that mine
operators are willing to consider the impact on their enrichment plants before changing gob well
operating settings or taking wells on and off line.
Even with these assertions, an air rejection demonstration by BOC Gases (paper by Shirley, et
al, 1997) encountered formidable difficulties in implementing a two-bed PSA process with feed
gas compositional variations. The paper described the demonstration at two scales, a
"demonstration" scale of 0.5 mscfd and "commercial" scale of 30-60 mscfd. BOC reported
good methane recovery (98 percent of available feed). The high quality product requirement
(-96 percent methane), however, necessitated feed rates lower than the nominal rating. At the
higher operating rates, Shirley, et al observed difficulties in controlling the composition of the
product gas. Operators paid considerable attention in the demonstration to limiting or
eliminating explosion hazards.
PSA suppliers are generally ready to design and build integrated facilities and turn them over to
customers once the facilities pass all performance tests. Assuming compliance with
maintenance procedures, PSA suppliers will warrantee plant performance during its operation.
At least one PSA gob gas enrichment plant is in the planning stage in Appalachia.
2.4 Selective Absorption
Sometimes referred to as Solvent Absorption, this process uses specific solvents that have
different absorption capacities with respect to different gas species. The petroleum industry
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commonly uses selective absorption to enrich gas streams. One firm that offers selective
absorption to reject nitrogen from methane is Advanced Extraction Technologies, Inc. (AET) of
Houston, TX. Bend Research Inc. of Bend, OR also developed nitrogen-selective absorbents
but does not offer a commercial scale plant (see Section 2.8).
AET demonstrated its nitrogen rejection technology with a 5 mmscfd unit installed at a
substandard natural gas field in Hugoton, KS. The AET process uses a special hydrocarbon
solvent that selectively absorbs methane while rejecting a nitrogen-rich stream in a refrigerated
environment. The process will accept variability in feed gas flow rates and composition. The
company expressed confidence that it can supply an integrated plant that will remove all four
gob gas impurities. By removing the oxygen in the first step there will be no harmful effect on
the solvent absorption unit. The company is ready to offer the system to interested mine
owners. AET's primary marketing target for the unit is removing nitrogen in low-grade natural
gas. Their interest lies in the much smaller gob gas market as well, however. Both markets
would be more attractive if the natural gas price were to improve.
2.5 Summary of Nitrogen Rejection Process Characteristics
Table 2 lists some of the more basic characteristics and differences for the six NRU systems
discussed above. The list is not complete; it only includes vendors that supplied technical and
cost details of their systems.
NRU Technology
Phase Change
Methane
Recovery
First Stage
Deoxygenation
Offer Design,
Build Integrated
Gob Gas Plant
UOP
PSA
No
Up to
95%
No
Yes
Nitrotec
PSA
No
Up to
95%
No
Yes
BOC
PSA
No
98%
No
Yes,
Possibly
AET
Selective
Absorption
No
96 to 98%
Yes
Yes
Darnell
Cryogenic
Liquefy
98%
Yes
Yes
Schedule A
Cryogenic
Liquefy
98%
Yes
Yes, after
trials
Table 2: Summary of Nitrogen Rejection Enrichment Systems
2.6 Other Processes
Processes to remove the contaminants (oxygen, carbon dioxide, and water vapor) are
commercially available from many established suppliers using a number of different techniques.
The integrated enrichment plant supplier most probably will be an NRU vendor and would select
and take overall responsibility for these other contaminant removal systems.
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2.6.1 Oxygen Removal
For reasons explained earlier and in Section 2.7, deoxygenation will be the,first process
component in the plants with cryogenic or solvent absorption NRU's. It will be the last step with
the PSA process, however, because the PSA plant will have removed most of the oxygen along
with nitrogen in the NRU.
All gob gas enrichment plants will use catalytic deoxygenation. There are other deoxygenation
techniques that are not as appropriate for this application. For example, using hydrogen to
form water presents an unacceptable combustion risk at a plant site. The catalytic
deoxygenation process is extremely exothermic, and every percentage increase in oxygen
concentration increases the temperature by about 700°F. The major concern is the upper
temperature limit that a plant can tolerate. It is not practical to operate the process above
2000°F, so a recycle mechanism would be necessary if inlet oxygen were to exceed 1.5
percent. It may be possible to use some of the heat for other parts of an integrated plant.
Shirley, et al (1997) refer to a catalytic reduction with hydrogen, although the paper provides no
details. Use of hydrogen will allow the removal of higher oxygen concentrations without
recycling, and at lower temperatures. The presence of hydrogen on site, however, will require
additional safety features.
There is also a possibility that the vent gas mixtures will reach the upper combustion limit for
methane and air as they exit the unit. These concerns are topics during engineering
optimization of the integrated process.
2.6.2 Carbon Dioxide Removal
Either amine units or membrane technology may be suitable carbon dioxide removal processes
as both are well-established technologies. No one has observed the sensitivity of either
process to other contaminants and flow variations associated with gob gas. An amine unit will
tolerate only low levels of oxygen in the feed stream, so the amine unit must be downstream of
the deoxygenation unit. Membrane processes may not be suitable to reduce carbon dioxide
concentrations to below one percent. Another alternative for removing carbon dioxide, one that
may offer cost advantages, is selective adsorption using a molecular sieve.
2.6.3 Water Vapor Removal
Dehydration of the gob gas is the simplest part of any integrated system design. Most system
suppliers will employ a molecular sieve dehydration stage because of its proven record and
economical operation.
2.6.4 Hydrogen Sulfide Removal
Hydrogen sulfide is the contaminant that gives "sour gas" its name. It is not as common as the
four major gob gas contaminants (for example, it is not present in the Northern Appalachian
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Basin), but when it occurs, it must remain below the 4 ppmv level for acceptance by natural gas
pipelines. The Gas Research Institute recently conducted field trials of several methods of
hydrogen sulfide removal. A-GRI article (Fisher, 1995) discusses process effectiveness, cost,
and disposal issues.
2.7 Technical Assessment
The Department of Chemical and Fuels Engineering at U of U performed a technical
assessment of the three NRU processes described in this report as the key components of their
respective integrated gob gas enrichment facilities. U of U used CHEMCAD, a simulation
package, to model the cryogenics and selective absorption process. Because PSA is a
dynamic process, the researchers used different analytical methods for that process. Appendix
E includes a copy of this report. The following is a summary of the principal findings:
2.7.1 Cryogenics Process
The cryogenic distillation process does not remove oxygen in the same proportion as nitrogen.
In order to avoid an explosive condition in the waste gas stream, the deoxygenation unit must
precede all other processes. Inlet oxygen concentration to the deoxygenation unit should
remain below 1.5 percent in order to avoid high temperatures in the unit. Since most gob gases
will have more than 1.5 percent oxygen, a recycle scheme is necessary and the deoxygenation
unit's flow capacity would need to be several times that of the main plant.
The process is technically feasible, but requires additional heat exchangers and process
equipment. Controlling this integrated process to accommodate compositional and flow rate
variations makes it the most complicated of the three NRU techniques.
2.7.2 Selective Absorption
Like the cryogenic process, deoxygenation must precede all other process steps for this
technique, and the deoxygenation unit must be large enough to remove the largest anticipated
concentration of oxygen (i.e. the oxygen content in the lowest quality feed gas that the unit can
accept). Selective absorption will yield a high purity product. The NRU itself is very flexible and
can accommodate compositional and flow variations.
2.7.3 Pressure Swing A dsorption
Nitrogen and oxygen will separate from methane in the same proportion in a PSA NRU, making
the final oxygen removal step simpler and not subject to a recycle configuration. If the process
were designed for high methane recovery under ideal conditions, there would be a concern for
flammability within the waste gas stream. The study established that high recoveries are
theoretically achievable using practical pressure ratios, given the adsorption isotherm data.
However, in multiple-bed PSA operations, recoveries will likely be lower and flammability risks
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will be lower. Because CHEMCAD cannot model the dynamic PSA process, the researchers
could not assess the extent of reduced methane recovery under actual conditions. The range
of recovery is approximately 80 to 95 percent (Shirley, et al [1997] report recoveries of about 98
percent). The lower end of that range will substantially impact product unit cost. Another way
of expressing that impact is that total cost will remain constant, but revenue will decrease
commensurately with reduced product recovery. PSA is a flexible process that may meet
compositional and flow rate changes by varying pressure ratios and cycle times. Even though
this is true in theory, Shirley, et al (1997) reported that product specifications could not be
maintained in the wake of some feed gas compositional variations. Their demonstration makes
it clear that building an integrated process to remove all contaminants at a mine with varying
feed gas changes (flow rates and compositions) will not be a trivial exercise, even though
individual contaminant removal processes are proven.
2.7.4 General
All of the three integrated processes are capable of functioning and yielding pipeline quality gas,
although many uncertainties remain. Providing process control for any of the three is going to
be a significant technical challenge in the presence of variations in the feed gas. In order to
maintain strict specifications for the product gas, it may be necessary to blend varying amounts
of a higher quality gas on an as-needed basis to maintain the feed within a permissible range.
An operator may have pure blending methane available from virgin coal boreholes (an
inexpensive option), from local natural gas distributors, or from recycling the enriched product
gas itself. If it is not practical to take blending methane from these sources whenever they are
needed, the operator may choose to install a pure methane surge system with enough storage
capacity to keep the plant operating during short periods of off-quality feed gas. Either
arrangement will allow the enrichment plant to adjust feed gas quality automatically, and it will
improve the plant's on-line time.
2.8 Emerging Technologies
This investigation identified other companies that are developing different nitrogen rejection
technologies that are potentially applicable to an integrated gob gas cleanup system.
2.8.1 Alternative PSA Technologies
Gas Separation Technology of Golden, CO offers a PSA process that uses narrow pore zeolites
as molecular sieves to effect separation. The company completed extensive laboratory tests of
the process in which zeolite adsorbed nitrogen and oxygen preferentially over methane.
Pressure drop and vacuum regenerate the zeolite and desorb the contaminants. The process
operates at around 150 psig and recovers about 90 to 95 percent of the methane. The
company reports that the process is capable of operating on gob gas containing as much as 75
percent air, and that they anticipate costs, for the NRU only, to be comparable to other PSA
supplier costs. This technology has not operated at commercial scale or with all four gob gas
contaminants.
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Technical and Economic Assessment of Potential to
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One other company, Northwest Fuel Development, Inc. (NW Fuel) of Lake Oswego, OR is
reporting (Soot, 1997) modified and improved PSA technology for nitrogen removal during tests
at an abandoned mine in Ohio. The company developed new and improved selective
adsorbents and optimized the cycle times to where the PSA essentially becomes a continuous
process. The process has several limitations. It can reject only about 50 percent of the
nitrogen from the feed. It retains about 70 percent of feed methane (while rejecting 30 percent),
and the feed gas must contain 85 percent methane or better. The prospect of low costs,
however, (NW Fuel estimates nitrogen rejection costs of $0.35 to $0.90 per mmBtu) may
compensate for the limitations. The company is concentrating on smaller units (e.g. several
hundred thousand cubic feet per day) which is a market niche that major suppliers have not
entered. Since this process is in the development stage, it was not considered in the analyses.
2.8.2 An Alternative Absorption Technology
Bend Research Inc. of Bend, OR, developed a series of nitrogen-selective liquid absorbents
based on transition metal complexes (as contrasted with AET's hydrocarbon solvents). The
process uses pressure and temperature controls and regenerates the absorbent. Methane and
other higher hydrocarbons pass through a standard packed column while nitrogen is selectively
absorbed in the column. A pump then directs the liquid absorbent to a flash tank where the
nitrogen desorbs, regenerating the absorbent. Absorbents under development exhibit tolerance
to carbon dioxide, hydrogen sulfide, and low (ppm) levels of oxygen.
The company projects costs for an NRU that may be comparable to competing units in the 5
mmscfd size range, but it is not clear what contaminant levels they assumed for such estimates
(Babcock, et al, 1997). There are no reports of field trials available.
2.9 Technical Assessment Summary
Even though the individual technologies for rejecting nitrogen, carbon dioxide, oxygen, and
water may be considered "established," a system comprising all of the four processes working
together on variable quality and flow, gob gas has not yet operated in commercial scale,
although one may soon do so. Carbon dioxide and water removal techniques are very well
established. Deoxygenation is less well established. Nitrogen rejection is not well established
with respect to gob gas field conditions because it operates mostly on relatively rich natural
gases not subject to extreme feed swings.
As nitrogen rejection is the most expensive of the four processes, NRU suppliers have been the
proposers of new integrated gob gas upgrade systems. Some of these firms have less
experience with removing oxygen and other contaminants, and they must use rigorous
engineering during process design to be certain that the integrated systems will function
reliably.
The technical assessment concluded that all three nitrogen rejection techniques could
successfully operate as the principal component of an integrated plant to enrich gob gas. A
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Technical and Economic Assessment of Potential to
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cryogenics unit would be risky, however, given the presence of oxygen and carbon dioxide and
the compositional and flow rate variations inherent with gob gas. In the selective absorption
process, oxygen removal must be the first step. Systems that carry oxygen through the
process units (such as PSA) would have to provide designs that remove the risk of explosion in
certain combinations of oxygen and methane. Shirley, et al (1997) showed, for the PSA
process, that this could be accomplished with careful engineering and design.
The interviews conducted for this assessment revealed that all three technologies reported by
their respective suppliers were technically feasible and free of unacceptable risks when fed with
gob gas, although no system supplier actually provided laboratory or field data to substantiate
such assertions. The Shirley, et al (1997) air rejection demonstration data underscores this
point. Removing all the impurities in an environment of varying feed gas composition and flow
rate will be a formidable task. With the exception of two of the cryogenic firms, system
suppliers are ready to make firm proposals to mine operators for integrated enrichment plants.
2.10 Outlook
There are two fundamental reasons why a gob gas enrichment facility is not in existence yet:
• Nitrogen rejection is still an emerging and developing technique, and removal of four
contaminants in one facility is, theoretically, feasible but unproven. The question of
technical feasibility comes down to one of proof. The industry that would supply the
systems believes that gob gas enrichment technology is straightforward, feasible, and
presents no unusual risks. On the other hand, the customer that would purchase the
systems is not in a position to spend several million dollars for a system that cannot be seen
and demonstrated. Gob gas enrichment is at the point of needing a commercial scale
demonstration facility, underwritten by a system vendor, that will prove technical functioning
of at least one of the systems offered and display any other benefits that would accrue to a
mine operator, including an attractive return on investment (As of December 1997, BCCK is
in the process of bringing an integrated gob gas enrichment facility on-line.).
• Low natural gas prices. Until late 1996 when natural gas prices started to move above two
dollars per million Btu's, inexpensive natural gas had made it less likely for system suppliers
and customers to jointly effect a full-scale demonstration of an integrated enrichment facility.
The following section shows that the cost of upgrading gob gas is a major percentage of the
current price that an operator would receive for this commodity in the marketplace.
On the other hand, there are indications that the conditions may soon become more supportive
of gob gas enrichment. The technical assessment performed as part of this report removed
many of the technical doubts on the three processes. Remaining challenges, such as design of
suitable control systems and maintaining feed gas specifications, appeanto require only
sufficient engineering and field trials. Mine operators and developers have become more aware
of gob gas use options (through the Coalbed Methane Outreach Program and other mine
industry sources). They should be willing to investigate projects at their own mines once
commercial demonstration of an enrichment plant becomes a reality. It is also reasonable to
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Technical and Economic Assessment of Potential to
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assume that some mine operators will invest in a facility because of the excellent return on
investment that some project configurations will yield, as detailed in the next section.
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Technical and Economic Assessment of Potential to
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3.0 COST ANALYSIS
3.1 Objective
The objective of the economic analysis portion of this report is to investigate the potential for
economic deployment of gob gas enrichment systems over the following ranges of feed gas
conditions:
Methane content - 30, 50, 60, 70, 85, and 90 percent
Gas flows - 2, 3, 4, 5, and 6 mmscfd
Early in the analysis it became clear that gob gas flows of less than 3 mmscfd and methane
concentrations of less than 50 percent could not provide positive cash flow with natural gas
prices at or somewhat above current levels. Therefore, the analysis includes flows of 3 mmscfd
and methane contents of 50 percent and above.
3.2 Cost Summary
A summary of each analysis appears in Table 3 which expresses costs as dollars per million
Btu for each of the three technologies. The sources of the data for Table 3 are Tables 1.1
through 1.20 in Appendix B. Each table covers a different feed gas case in terms of flow rate
and methane content. The main part of the analysis described below entailed estimating capital
and operating costs for each feed gas condition and comparing the total costs with revenues
that might reasonably be expected by selling gas to natural gas transmission companies. The
discussion includes methods for profitable plant siting and strategies for reducing plant costs.
The analysis determined that the costs of the three integrated technologies using the three
different NRU approaches were not significantly different, given the uncertainties in the cost
data. Costs of individual enrichment technologies depend on specific mine conditions, exact
engineering designs, and cost agreements that mine operators can work out with individual
vendors. The report lists the enrichment costs as both a "low-end" estimate and a "high-end"
estimate. The error within each of these estimates is probably about 20 percent due to
uncertainties in the cost data and also due to the fact that cost data on a commercially
operating integrated plant are not available.
3.3 Plant Size Selection
When a potential operator plans the size of an enrichment facility there are several factors to
consider. The first is how much gob gas will be available for the plant on an average day and
how much variation will there be. Second, what is the average composition of the feed gas and
how does it fluctuate. Third, what are the plant sizes in terms of inputs that are available.
Fourth, how much of the feed gas would be consumed by the plant's compressors and other
gas fueled machinery (this analysis assumed that the most economical energy source for the
compressors would be the gob gas itself having undergone minimal cleaning or other
treatment). Fifth, how much gas product (sales gas) would such a plant yield on a daily basis.
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Technical and Economic Assessment of Potential to
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And sixth, what percentage of the time would the plant actually run (i.e. availability or on-line
percentage).
In selecting nominal case increments the team decided to use average daily flow of gob gas,
because mine owners can most easily relate to that parameter (although getting an accurate
projection of daily flow is not always possible).
Table/Inlet Gas Conditions
TABLE 1.1-3 mmscfd, 50 percent
TABLE 1.2-3 mmscfd, 60 percent j
TABLE 1.3-3 mmscfd, 70 percent
TABLE 1 .4 - 3 mmscfd, 85 percent
TABLE 1 .5 - 3 mmscfd, 90 percent
TABLE 1 .6 - 4 mmscfd, 50 percent
TABLE 1 .7 - 4 mmscfd, 60 percent
TABLE 1.8-4 mmscfd, 70 percent
TABLE 1.9-4 mmscfd, 85 percent
TABLE 1.10-4 mmscfd, 90 percent
TABLE 1.11-5 mmscfd, 50 percent
TABLE 1.12-5 mmscfd, 60 percent
TABLE 1.13-5 mmscfd, 70 percent
TABLE 1.14-5 mmscfd, 85 percent
TABLE 1.15-5 mmscfd, 90 percent
TABLE 1.16-6 mmscfd, 50 percent
TABLE 1.17-6 mmscfd, 60 percent
TABLE 1.18-6 mmscfd, 70 percent
TABLE 1.19- 6 mmscfd, 85 percent
TABLE 1.20- 6 mmscfd, 90 percent
Low-end Estimate
3.34
2.54
1.94
1.55
1.45
2.95
2.27
1.76
1.43
1.34
2.83
2.14
1.63
1.29
1.21
2.52
1.94
1.50
1.22
1.14
High-end Estimate
3.85
2.97
2.29
1.66
1.55
3.45
2.67
2.08
1.65
1.42
3.19
2.44
1.89
1.49
1.38
2.82
2.19
1.73
1.41
1.30
Table 3: Summary of the Low and High Gob Gas Enrichment Costs
($/mmBtu)
A mine that projects 3.0 mmscfd will only have about 2.65 mmscfd available (after subtracting
compressor fuel), but is limited to the choice of a 3 mmscfd plant from most vendors. Obviously
that plant will be under-employed on all but peak production days. As capital costs are many
times as high as operating costs, load factors significantly below 85 or 90 percent may be very
costly. Finally, sales gas quantities will vary greatly between systems for a given available flow
increment because two other factors are at work: methane loss within the process, and
expected reliability (on-line) percentage. Unless system suppliers find an easy way to
customize plant size to each mine's gas profile, there will be certain awkward and costly
matches (e.g. the 3 mmscfd case cited above). A much better case is a mine having 4 mmscfd
available that purchases a 3 mmscfd unit. Only on low flow days will that plant be under-
utilized, keeping unit capital costs low. A relatively small amount of gob gas flared or emitted
will cause the only extra cost resulting from this case.
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Technical and Economic Assessment of Potential to
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3.4 Cost Data and Engineering Estimates
The sources for capital and operating cost data are the 1993 DOE Report supplemented with
data collected from vendors during the preparation of this report. Where prices were not readily
available on certain items, the report assumes that similar components (e.g. removal units for
oxygen, water vapor, or carbon dioxide, and compressors) would have similar capital costs so
as not to skew one technology versus another. Costs for scaled-up units (except for
compressors that are linearly proportional to the flow rate) increase according to the 0.6 rule.2
The reader should note that, with all the cost standardization, interpolation, and
extrapolation, as well as time elapsed since the 1993 DOE Report, these cost estimates
must be considered preliminary, particularly in light of the new air-rejection
demonstration data published by Shirley, et al (1997).
A more rigorous engineering analysis is necessary to narrow the cost uncertainties,
3.4.1 Compression Requirements
Gas compression requirements comprise a large percentage of capital costs. The report
assumed that the feed gas is available at atmospheric pressure (14.7 psia) and that the sales
gas pressure is 600 psia. That pressure may be too low for larger pipelines and too high where
gas may be sold at distribution pressures. In any case, an interested mine operator may
substitute the actual delivery pressure for the particular case before using these estimates. The
analysis used the following standard engineering calculations and assumptions to build the
estimates:
• Cryogenic Process: Inlet pressure for the cryogenic process is about 800 psi.
During the DOE Report preparation, investigators assumed that process outlet
pressures were close to atmospheric. However, Schedule A reported that it is
between 80 and 190 psi, thus decreasing power requirements for the sales
compressor. This analysis assumed an outlet pressure of 80 psi.
• PSA Process: Nitrotec's PSA is low-pressure separation (below 50 psi) while UOP's
PSA operates at around 150 psi. The assumption in this report is that the pressure
of the outlet streams in the PSA process is close to the inlet pressure. Analysts
calculated compression requirements and compared them to compression charts
supplied by the vendors. In some cases they had to defer to vendor numbers. The
recycle compression requirements were more difficult to estimate. It is reasonable
to assume a linear relationship for recycle compression requirements with respect to
flow rate, and an inverse linear relationship with respect to methane content.
2 The "0.6 Rule" approximates the cost of a larger or smaller piece of equipment by taking the ratio of the new size
rating (e.g. flow capacity) to the original size and raising it to the 0.6 power. For example, Tractor B is twice as large
as Tractor A, but it may cost just 1.52 as much as Tractor A.
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Technical and Economic Assessment of Potential to
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Selective Absorption Process: Inlet pressure for AET's process is about 300 psi.
Calculated feed and sales compression requirements were consistent with numbers
provided by the company.
3.4.2 Methane Recovery
f
Methane recovery refers to the percentage of feed gas methane that exits the process as sales
gas. The difference between the recovery percentage and 100 percent represents the methane
lost during processing. Methane in gob gas used as fuel for process compressors (see 3.4.3
below) does not enter into this calculation. The analyses assumed recoveries of 90 percent for
PSA processes and 96 percent for selective absorption and cryogenic processes.
3.4.3 Fuel Requirements
The most economical energy source for the compressors is the unprocessed gob gas which
would be diverted from the enrichment processing system. The moisture content of the
saturated gob gas decreases the quantity of methane available for powering the compressors.
The analysis used adjusted heating values of 680 Btu/scf for the gas containing 70 percent
methane and 825 Btu/scf for the gas containing 85 percent methane. Compressor fuel
requirements are approximately 10,000 Btu/hr/hp, using a well established rule of thumb.
The cost assumptions included a very simple gas cleanup module for the compressor fuel to
remove most of the particulates and moisture. Engine-driven units are more practical and less
costly to run than electric units. It is not necessary (and much too expensive) to take partially
processed feed gas from the enrichment plant and use it for compressor fuel. Dewpoint
(condensation) problems remain under control by keeping the exhaust hot enough in the
presence of acid gases. Sulfur dioxide is not a problem with gob gas combustion as there is
little or no sulfur in the gas. Developers may have to file an extensive air permit application for
the compressor engines. Engines must employ state-of-the-art, lean-burn technology to
minimize the production of NOX, which will be less than 35 tons per year for any of the plant
configurations reported on in this report. The application will probably contain a BACT analysis
proving that there is no better alternative commercially available.
3.4.4 Estimation of Error
All of the numbers used in this analysis will contain a certain amount of error - as much as 20
percent or even up to 40 percent - based on the technical and cost uncertainties raised in the
new paper by Shirley, et al (1997). For each of the three technologies, the NRU is the largest
component and, therefore, has the largest impact on plant cost estimates. NRU installed cost
estimates cannot be accurate until project specific engineering details are available. The report
tends toward conservative plant estimates by assuming purchase of new equipment (except for
carbon dioxide removal units) and using a 10 percent contingency factor applied to the entire
plant. These are probably good first order estimates of capital cost, but they cannot be relied
on when making technology or supplier selection. A more sophisticated economic analysis
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Technical and Economic Assessment of Potential to
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would not be more useful at this stage because engineering analysis, optimization, and full-
scale demonstration must take place first.
Similarly, the operating cost estimates appear to be conservatively high. The tables list one full-
time operator for each plant even though some installations will run well automatically, with
attention required from a fraction of one full time position. Assumed standard amounts for
supervision and overheads are subject to reduction or elimination in certain cases.
Appendix A contains a discussion of how the analysis projected the remaining costs. Using
these explanations a mine operator may substitute cost factors based on real physical and
economic conditions in the area to arrive at a more realistic result.
3.5 Analysis Format
Appendix B presents two cost analysis formats:
• The first is Unit Cost Analysis comprising one sheet for each of the twenty selected inlet
gas conditions in the ranges from 3 to 6 mmscfd and 50, 60, 70, 85, and 90 percent
methane. Each of these analyses calculates a low-end and a high-end cost. Unit costs
are the result of dividing total annual plant costs by the expected energy sales quantity.
The purpose of this format is to provide a simple screening technique and to observe
the effects of changing gas flows, plant size, and gas compositions. The major
simplifying assumption in this analysis is the use of the capital recovery factor (CRF)
representing a 10 year economic life and an internal rate of return requirement of 25
percent. The total capital costs use this CRF of 0.28 to arrive at an annual capital
"cost." The 10 year CRF is a fair approximation of a range of project lives. For
example, if a project were to last only eight years the CRF would be 0.30, and with a
fifteen year life (as shown on the Cash Flow Statements discussed in the following
paragraph) the CRF would drop slightly to 0.26. Table 3 contains the unit cost results of
all twenty scenarios.
• The second format is a Cash Flow Statement (for selected scenarios only) that uses an
income statement format with some cash flow adjustments and an internal rate of return
calculation. The purpose of including cash flow statements is to depict typical business
realities of a gob gas enrichment project including allowances for royalties, severance
taxes, and ad valorem taxes. One element of the cash flow statement that can only
come from interested mine operators is an allowance for state and federal taxes. Tax
estimates do not appear because of the broad range of possible tax situations. Another
assumption that simplified the analysis is that all capital for the project would be equity
(i.e. no debt would be used to leverage the capital purchase). This is a conservative
assumption, especially during periods of low interest rates. There are lines in the
model, however, for quantifying effects of debt repayment on annual cash flow.
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Technical and Economic Assessment of Potential to
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3.6 Analysis of Results
In spite of possible estimation errors and the lack of engineering standardization among the
different proposed systems, it is quite possible to draw some conclusions from the cost and
cash flow analyses appearing in this report. Charts of certain key relationships (see text below
and Figures 1 through 4 on the following pages) use data from Table 3.
3.6.1 Cost Sensitivity to Gas Flow Rate
Figure 1 shows that low-end costs of the product gas decrease significantly as the size of the
plant and available gob gas supplies increase. The chart does not show plant costs below 3
mmscfd because most vendors do not offer plants below that size, and the results would be
uneconomical in many markets at today's price for natural gas. At the higher plant sizes, the
unit gas costs appear quite promising, although it should be noted that these are low-end costs.
3.4
3.2
3.0
2.8
2.6
2.4
2.2
2.0
1.8
1.6
1.4
1.2
1.0
• Inlet Methane Content - 50%
• •••*••• Inlet Methane Content - 60%
.-•••-•. Inlet Methane Content - 70%
-••»••• Inlet Methane Content - 85%
—*— Inlet Methane Content - 90%
3.0 3.5 4.0 4.5 5.0
Feed Gas Flow Rate (mmscfd)
5.5
6.0
Figure 1: Low-end Costs versus Feed Gas Flow Rate
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Technical and Economic Assessment of Potential to
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3.6.2 Cosf Sensitivity to Methane Content of the Feed Gas
Figure 2 plots the unit cost of gas enrichment against the percentage of methane in the gob
gas. While system suppliers indicate the ability to enrich feed gases with as little as 50 percent
methane, they have had very little experience operating at this level. Unit process costs are
very sensitive to decreasing feed gas quality because the product yield is decreasing while
rejection costs keep rising. Enrichment may not be an affordable option with gob gas averaging
much below the 70 percent methane level, unless natural gas prices were to increase
substantially. A mine that wants to enrich lower quality gob gas may blend it with a high quality
source, produced or purchased, to achieve an acceptable feed gas. While that means
processing a quantity of already valuable gas, this strategy may be able to take advantage of
the economy of scale of the larger plant needed to enrich the blend.
At the upper end of the feed gas quality range there is little cost advantage for each increment
of methane content (e.g. it costs almost as much to enrich a 90 percent gas as an 85 percent
gas). The project developer should investigate less expensive options for enriching 90 percent
gas. Section 2.0 discusses removing only the oxygen and water vapor and then blending with
pure methane or spiking with a high heat value fuel such as propane.
3.4
3.2
3.0
2.8
2.6
2.4
2.2
2.0
1.8
1.6
1.4
1.2
1.0
_*__
•-•*-"
.......
Flow Rate - 3 mmscfd
Flow Rate - 5 mmscfd
Flow Rate - 6 mmscfd
•<#
50
60 70 80
Methane Content in Feed Gas (%)
90
Figure 2: Low-end Costs versus Methane Concentrations in the Feed Gas
Figures 3 and 4 show plots of the high-end costs versus flow rates at various methane inlet
concentrations and versus methane content in feed gas at various flow rates. The trends of
these high-end estimates are the same as the low-end costs.
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Technical and Economic Assessment of Potential to
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4.0
3.5
3 3.0
2.5
2.0
1.5
1.0
• Inlet Methane Content - 50%
••••*••• Inlet Methane Content - 60%
.-.*-.- Inlet Methane Content - 70%
• ••«••• Inlet Methane Content - 85%
_ *. — inlet Methane Content - 90%
3.0 3.5 4.0 4.5 5.0
Feed Gas Flow Rate (mmscfd)
5.5
6.0
Figure 3: High-end Costs versus Feed Gas Flow Rates
3.6.3 One Plant versus Two
Figure 1 shows the rather steep cost increases for smaller daily flows. If two or more gob gas
flows could be gathered at one larger plant site the operation might be much more economical,
depending on the distance of the piped raw gas. Figure 5 is a simple break-even analysis that
illustrates that concept. The analysis takes the unit cost of enriching two streams of 3 mmscfd
at 85 percent methane at two separate PSA plants ($1.55 from Table 3) and compares it with
the unit cost of the same gas streams that are processed at one 6 mmscfd plant for ($1.22 from
Table 3) plus the costs of compressing and piping half of the gas stream over various distances
representing the distances between two hypothetical mine sites. The break-even analysis
shows that gas may be sent up to 8 miles to consolidate flows with an 8 inch shallow burial pipe
before it becomes less expensive to build two plants. Assuming that the project uses a 6 inch
shallow burial pipe, gas may be piped almost 9 miles. If the 6 inch pipe is not buried, then gas
may be conveyed more than 15 miles. The analysis did not take into account the difficulties or
costs associated with right-of-way acquisition where the mine does not control the land between
the two sites.
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Technical and Economic Assessment of Potential to
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4.0
3.5
£ 3.0
2.0
1.5
1.0
50
Flow Rate - 3 mmscfd
Flow Rate - 4 mmscfd
Flow Rate - 5 mmscfd
Flow Rate - 6 mmscfd
60 70 80
Methane Content in Feed Gas (%)
Figure 4: High-end Costs versus Methane Concentrations in the Feed Gas
2.40
ft.
»
o
2.00 - -
1.60 -
1.20 -'
0.80 -
0.40 -
0.00
3 mmscfd
6 mmscfd Plant
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15
Miles
- Cost for 2-3
mmscfd plants
— 6" above
ground
- 6" shallow bury
8" above
ground
- - - 8" shallow bury
Figure 5: Cost Comparison for Piped Gob Gas to a 6 mmscfd Plant versus Two 3 mrnscfd
Plants
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Technical and Economic Assessment of Potential to
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3.6.4 Cash Flow Analyses
Analysts selected two project configurations that are financially attractive and one that is not
quite marginally attractive for further examination in a discounted cash flow format. Tables 2.1,
2.2, and 2.3 are in Appendix B. The two cases using 85 percent feed gas (Tables 2.2 and 2.3)
show pre-tax internal rates of return between 26 percent and 33 percent that would be
interesting to many investors. The lower 26 percent return results from using the high-end
costs and 5 mmscfd v. low-end costs and 6 mmscfd for the 33 percent return. The 70 percent
methane case with a daily flow of 5 mmscfd shows a pre-tax return of 22 percent which is only
marginally attractive, even using low-end costs. Of course this result would improve somewhat
if the project were leveraged with debt financing. Profitability could also improve if there were
no royalty requirement or if gas prices were to increase.
3.6.5 Future Cost Trends
In general, the cost data reveal that the larger projects with smaller amounts of impurities are
the only profitable projects. This picture is very similar to the 1993 assessment of gob gas
enrichment. If anything, plants may be somewhat less expensive now, but cost estimates
presented in either report did not result from actual integrated plant field experience (because
there has been none), so small trends are difficult to verify. One could speculate that
enrichment costs may decrease once field operations begin, allowing the smaller, more
contaminated gas streams to be profitably upgraded. Some reasons might be:
• As more systems go on-line, technical uncertainties and risks will lessen, which may
allow reduced markups.
• Competition among several system suppliers of three different technologies will maintain
pressure on costs.
• Standardization of plant modules will contain manufacturing costs.
• As operators gain more field experience they may be able to take advantage of remote
monitoring and process adjustment to reduce operator costs.
• Mine operators may see opportunities to gather larger gob gas flows and to maintain
higher methane percentages in the feed gas to save processing dollars.
3.6.6 Cost Study Conclusions
Cost estimates of the technologies indicate that gob gas enrichment projects that sell upgraded
gas into the natural gas transmission or distribution market may be cost effective relative to
current natural gas prices if 80 percent methane feed gas is consistently available in daily gas
flows of 5 mmscfd or higher. This judgment relies on the fact that the analyses used
conservative estimates of capital and operating costs for typical plants operating under an
assumed set of operating conditions. With this level of cost estimation, it is not possible to
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choose among the three technologies. Enrichment costs are very sensitive to project size and
methane content. If two or more projects are within about 10 miles of one another, the
developer should study the possibility of enriching the two gas streams together at one common
plant.
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Technical and Economic Assessment of Potential to
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4.0 CONCLUSIONS
The following sections summarize the findings of this report.
4.1 Commercial Opportunities
At this writing there has been no full scale demonstration of gob gas enrichment, but this
situation may be changing. Opportunities exist to develop facilities because many mines have
gob gas flows that would support financially attractive projects. Three basic technologies for
nitrogen rejection have been proven and are being sold by a number of vendors for use on
substandard natural gas. Gob gas enrichment, however, requires rejection of oxygen, carbon
dioxide, and water vapor in addition to nitrogen, and all four processes would have to combine
in an integrated plant. The coal company, system vendor, or project developer that first
assumes the risks and goes through the process of implementing an integrated enrichment
plant will have established a dominant position in a new market.
4.2 System Suppliers Willing to Demonstrate
Suppliers of nitrogen rejection technologies are ready for the opportunity (and are even
beginning) to demonstrate full scale gob gas enrichment in an integrated plant using processes
that have been proven individually on other feedstocks.
4.3 Technical Concerns
There are a number of technical concerns relating to the ability of an integrated enrichment
plant to handle gob gas in spite of the confidence expressed by system suppliers. For example,
the plant must be tolerant to the flow and quality fluctuations inherent with gob gas; it must be
able to function in the presence of other contaminants such as oxygen and carbon dioxide; and
it must remove any possibility of accumulating explosive combinations of methane and oxygen.
Plant designers need to develop a complex control architecture for remote trouble free
operation.
4.4 Cost Effective Projects
Assuming that technical concerns can be overcome and that cost estimates generated for this
report are reasonable, there is a good likelihood that gob gas projects with a certain range of
gas quantity and quality will be cost effective and attractive to investors on their own merit. It is
also possible that capital and operating costs will improve after mine operators and system
suppliers gain field experience. To ensure profitable projects, other factors must be positive as
well:
• Projects must maintain feed gas supply within reasonable quality and quantity ranges.
25
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Technical and Economic Assessment of Potential to
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.There must be a cooperative pipeline customer within a reasonable distance from the mine.
The mine operator must arrange to keep a high percentage of revenues with minimal
payments for royalties and taxes.
4.5 Effects of Natural Gas Prices on Profitability
At current gas prices (the analysis assumed that the pipeline would pay $2.00 per mmBtu and
charge $0.30 for a net of $1.70 per mmBtu), only the mines that can produce gob gas flows
above 4 mmscfd with methane content consistently better than 80 percent can expect to
develop strong projects. Figures 1 and 2 are useful for scaling off the impact of changing the
gas price. For example, if gas prices were to increase by 15 percent from current levels, a gob
gas with close to 70 percent methane might become economically feasible for the same sized
project, or a 3 mmscfd daily gas flow project may become attractive with the 80 percent quality
feed gas.
If natural gas prices were to move even further upward, the higher revenues would allow
projects with smaller and/or lower quality gas supplies to succeed. For example, if net
revenues (after transportation costs) were to permanently rise above $2.20 per mmBtu (about
30 percent above the $1.70 level), most or all of the projects summarized on Table 3 would be
financially attractive.
4.6 Market Incentives
Although one commercial scale plant may soon be on-line, the industry has been slow to take
advantage of available technology. What will accelerate the establishment of more projects?
What will sustain the industry so that many facilities go on-line after the first few? It may be
good enough for a system supplier to provide guarantees to a customer to protect against
economic loss. But if the plant turns out to be unsatisfactory, and the vendor must return the
purchase price, a mine operator would still not be able to recover the costs associated with
management time, training time, and opportunity losses (from not pursuing other gas recovery
and use options).
The chances of a facility getting built will depend greatly on the monetary rewards available
from upgrading and selling the methane. The cost studies show that only the larger facilities
with high methane content in the feed gas will have a good chance of providing a fair rate of
return to the investor. Smaller projects, or any project with medium to low methane content will
most likely have to depend on one or more incentives that would have the effect of reducing
investor risk and raising investment returns. Possible incentive mechanisms include the
following:
• Section 29 Non-Conventional Fuel Tax Credits. This federal tax program is ending, but
there are some pre-existing wells that may still be able to take advantage of the credits.
26
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Technical and Economic Assessment of Potential to
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• Greenhouse Gas Emission Reduction Reports. Mine operators may be able to take
advantage of these reports for financing projects that mitigate global warming. Projects
that use methane that would otherwise have gone to waste are especially good
candidates for funds from large utility or industrial firms that choose to offset their own
greenhouse gas emissions. If global warming reports, at current full value, could
support any one of the projects modeled in this report, each would show a robust and
financeable cash flow statement.
• Risk Sharing Using Project Structure. Often a creative contractual structuring of project
entities and roles will provide incentives for project implementation. In a joint venture or
a less formal relationship between a mine operator and a system supplier, each party
may take on assigned risks and rewards that are commensurate with its primary
function.
• The mine operator may assume the "gas risk" - the responsibility that gob gas of
acceptable quality and rate of flow will consistently flow to the enrichment plant.
Perhaps a "put or pay" clause that penalizes the operator when gas deliveries are below
specific limits could enforce compliance.
• The system supplier may accept the technical risk that the plant will perform up to
specified standards. This entity may also provide a maintenance contract with an
extended warrantee of performance as long as that contract is in place.
• Both parties could share in the financial risk by forgoing receipt of expected payments
during periods when project cash flow cannot meet debt service (or other payments for
capital).
The alternative energy industry has produced many innovative incentive mechanisms that have
encouraged implementation of projects that otherwise would have stalled in an early phase.
Some useful strategies that will apply specifically to gob gas enrichment projects appear in a
new handbook published by EPA entitled A Guide to Financing Coalbed Methane Projects.
4.7 Financial Assistance: State, Local, and Federal
CMOP recognized that one barrier to coal mine methane recovery is difficulty in obtaining
financing for economically sound methane recovery projects. CMOP published a document
entitled Finance Opportunities for Coal Mine Methane Projects: A Guide to Federal Assistance
and two guides for state and local finance opportunities (in Pennsylvania and West Virginia).
These describe a broad scope of programs and funds available from the respective
governments. Most federal assistance is in the form of grants and loans to state agencies for
reallocation to local businesses. The guides provide an overview of assistance programs and
profiles of the most promising federal programs for assisting coal mine methane projects.
These guides are available from CMOP (see contact information in Appendix F).
27
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Technical and Economic Assessment of Potential to
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4.8 CMOP Assistance
CMOP offers help to developers of methane use projects. The assistance ranges from
activities that support specific projects to documents that help developers work through
common problems. The following is a list of potential assistance:
• Pre-feasibility assessments.
• Solutions to legal or regulatory obstacles.
• Information on interested venture partners.
• Identification of potential financial sources.
• Advice on overcoming market entry barriers.
• Networking to share publicly available technical innovations.
• Public recognition for voluntary achievement.
• Seminars and workshops on selected subjects.
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Technical and Economic Assessment of Potential to
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APPENDIX A - ASSUMPTIONS USED IN THE COST ANALYSES
Appendix A
-------
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Technical and Economic Assessment of Potential to
Upgrade Gob Gas to Pipeline Quality
1.0 ASSUMPTIONS USED IN THE COST ANALYSES
The following sections describe the methods and parameters used in the cost analyses. This
information supplements the discussions in Section 3 of the report.
Presentation Format
The analyses appear in Appendix B in two formats. The first (B.1) presents candidate
scenarios for a range of flows and methane contents in a simple unit cost analysis using first
year operating costs and an annual capital recovery factor of 0.28 times the total investment
cost (which represents a 25 percent rate of return for a ten year life of project). Each table has
a column for low-end and high-end costs. The second analysis format (B.2) is a fifteen year
cash flow proforma statement showing expected internal rates of return for a sampling of the
more promising of the scenarios from B.1. This is the fairest way to compare costs of one
project scenario to another. One of the cash flow statements use high-end costs and two use
low-end costs.
Another purpose of this exercise is to demonstrate to mine operators whether or not an
enrichment system could be economically attractive at their location. While no one actual mine
situation will fit the selected criteria, interested mine operators can change assumptions where
appropriate to test applicability of a particular system.
Gas Production
There are 20 cases in Appendix B.1, which are all permutations of two variables: input flows of
3, 4, 5, and 6 mmscfd of gob gas averaging 50, 60, 70, 85, or 90 percent methane. The sample
cash flow analyses assume that the duration of gob gas production is at least as long as the
fifteen year project economic life. Estimated average available sales gas flows associated with
each discrete feed input, take into account average methane content, process losses, and
methane consumption for the compressors.
System Availability
There are a number of reasons why a complex enrichment facility cannot produce to its full
capacity 100 percent of the time. First, the gob wells themselves cannot always produce
expected qualities and quantities of feed gas because of natural fluctuation and well
maintenance programs. Second, the gathering system will experience outages and periods of
low flow. Third, the integrated enrichment facility with its many components and compression
stages must have idle periods for scheduled and unscheduled outages. Fourth, the delivery
system and the pipeline's ability to always accept sales gas will experience interruptions. To
mitigate the feed gas fluctuations a mine operator may be able to select a plant capacity that
coincides with expected periods of low flow so it will be fully employed most of the time. But for
such cases, average and peak gob gas flows will exceed plant capacities so that operators
must vent or flare significant quantities of gas even while the plant runs at capacity. To reflect
the sum of these factors, the analysis assumes a plant availability of 90 percent.
Appendix A
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Technical and Economic Assessment of Potential to
Upgrade Gob Gas to Pipeline Quality
Gas Revenue
This analysis assumes an average heat content of 980 Btu per scf for the sales gas. The
assumed market price is $2.00 per mmBtu and the transportation cost paid to the pipeline is
$0.30 per mmBtu, for a net revenue of $1.70 per mmBtu which is then escalated at three
percent per year after year one. The mine's share of the gross gas revenue after a 12.5
percent royalty is 87.5 percent.
Sales Gas Specifications
1. Solids Free of
2. Oxygen 10ppm
3. Nitrogen* Max. 3 percent
4. Carbon Dioxide* Max. 3 percent
5. Hydrogen Sulfide 1/4 Grain/100
6. Total Sulfur 20 Grains/100
7. Liquids Free of
8. Water Vapor 7 Ibs/mmscf
9. Hydrocarbon Dew Point 15 degrees F @ 100-1000 psi
10. Heating Value Min. 980 Btu/scf
11. Temperature Max. 120F
12. Delivery Pressure 100-800psig
* Total Inerts (Combined) Max. 3 percent
Limits of Analysis
Since the primary intent of this analysis is to compare enrichment cases with different flows and
qualities, the "borders" of the physical plant to be studied were narrowed somewhat to include
only the enrichment system and a modest delivery configuration. The model assumes that the
mine would already have in place a series of gob wells with low pressure blowers and some
piping. It would be a small cost for most mines to complete this gathering system, and that cost
fits within the contingency. Therefore, sunk costs are original well installation costs plus the
costs of installing new wells during the project. Also gob well maintenance service that would
be required anyway does not enter into this analysis. The model further assumes that the
enrichment plant would be close to the gathering system outlet so there will be no additional
gathering costs (except in the break-even analysis, Figure 5, which compares two smaller
plants each located at separated mines with a larger plant). The delivery system consists of a
right-of-way (ROW), a one mile pipe (assuming a 6 inch 250 psi shallow buried pipe), a 600 psi
sales compressor, a metering station, and an interconnection with a natural gas pipeline totaling
$150,000. Some actual interconnections may require pressures of 1000 or 1200 psi, and the
additional cost of injecting at 1200 psi v. 600 is in the range of $0.20 per mmBtu.
Capitalization
For the sake of simplicity the model assumes a 100 percent equity case (i.e. with no project
debt). While a project such as this could raise several types of financing and could use
Appendix A 2
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Technical and Economic Assessment of Potential to
Upgrade Gob Gas to Pipeline Quality
leverage to increase profit and decrease the impact on a mine operator's balance sheet, it
would be difficult to depict a debt structure that would be applicable to all. For the convenience
of a potential developer there are lines in the Cash Flow Analyses left open to calculate the
impact of debt interest payments and principal repayments on annual cash flow.
Depreciation
A depreciation calculation is necessary to predict federal and state income taxes. This analysis
is presented "pre-tax" (see the discussion on taxes below), so depreciation would not need to
be analyzed. However, the model included it for those that wish to refine the estimates by
applying their own tax situation to the project.
The majority of tangible capital costs follow the Modified Accelerated Cost Recovery System to
calculate a depreciation allowance. This analysis used a seven year recovery period with the
half year convention, 200 percent declining balance method, and no salvage value. Pipeline
and ROW depreciation is straight line over a fifteen year useful life. The depreciation
allowances stretch over the first eight years of the project using the following percentages of
depreciable costs: 14.29, 24.49, 17.49, 12.49, 8.93, 8.92, 8.93, and 4.46 percent.
Operating Expenses
Operating expenses are direct and indirect costs associated with field operations and
maintenance of the enrichment system, compressors, and delivery system. Costs include
direct and supervisory labor, labor benefits and expenses, supplies, fuel and utilities, repair
labor and expense, and other direct and indirect costs. Some of the operating expense data
came from the system vendors; others, such as maintenance labor and materials, and local
taxes and insurance, appear as percentages of plant cost. Personnel assumptions are one full
time operator for all cases except cryogenics plants where one and one quarter operator would
be needed. The model accounts for supervision labor and overheads as a standard override on
labor. Operating expenses also escalate at three percent for the life of the project.
Federal and State Taxes
The analyses are all pre-tax for simplicity and because of the difficulty of selecting a
representative average tax situation for each mine. As no taxes were figured, no
tax credits such as depletion allowances or non-conventional fuel tax credits (Section 29
credits) appear in the analysis. In the case of Section 29 credits, there will be fewer and fewer
mine operators that will be able to take advantage of them as time passes.
Miscellaneous Taxes
Each case assumes a five percent severance tax on the value of all severed minerals (in this
case the mine's share of the methane value) and an ad valorem tax at a rate of three percent of
the mine's share of the methane. This is similar to amounts that would be paid in West Virginia.
Appendix A
-------
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Technical and Economic Assessment of Potential to
Upgrade Gob Gas to Pipeline Quality
APPENDIX A - ASSUMPTIONS USED IN THE COST ANALYSES
-------
-------
1.0 ASSUMPTIONS USED IN THE COST ANALYSES
The following sections describe the methods and parameters used in the cost analyses. This
information supplements the discussions in Section 3 of the report.
Presentation Format
The analyses appear in Appendix B in two formats. The first (B.1) presents candidate
scenarios for a range of flows and methane contents in a simple unit cost analysis using first
year operating costs and an annual capital recovery factor of 0.28 times the total investment
cost (which represents a 25 percent rate of return for a ten year life of project). Each table has
a column for low-end and high-end costs. The second analysis format (B.2) is a fifteen year
cash flow proforma statement showing expected internal rates of return for a sampling of the
more promising of the scenarios from B.1. This is the fairest way to compare costs of one
project scenario to another. One of the cash flow statements use high-end costs and two use
low-end costs.
Another purpose of this exercise is to demonstrate to mine operators whether or not an
enrichment system could be economically attractive at their location. While no one actual mine
situation will fit the selected criteria, interested mine operators can change assumptions where
appropriate to test applicability of a particular system.
Gas Production
There are 20 cases in Appendix B.1, which are all permutations of two variables: input flows of
3, 4, 5, and 6 mmscfd of gob gas averaging 50, 60, 70, 85, or 90 percent methane. The sample
cash flow analyses assume that the duration of gob gas production is at least as long as the
fifteen year project economic life. Estimated average available sales gas flows associated with
each discrete feed input, take into account average methane content, process losses, and
methane consumption for the compressors.
System Availability
There are a number of reasons why a complex enrichment facility cannot produce to its full
capacity 100 percent of the time. First, the gob wells themselves cannot always produce
expected qualities and quantities of feed gas because of natural fluctuation and well
maintenance programs. Second, the gathering system will experience outages and periods of
low flow. Third, the integrated enrichment facility with its many components and compression
stages must have idle periods for scheduled and unscheduled outages. Fourth, the delivery
system and the pipeline's ability to always accept sales gas will experience interruptions. To
mitigate the feed gas fluctuations a mine operator may be able to select a plant capacity that
coincides with expected periods of low flow so it will be fully employed most of the time. But for
such cases, average and peak gob gas flows will exceed plant capacities so that operators
must vent or flare significant quantities of gas even while the plant runs at capacity. To reflect
the sum of these factors, the analysis assumes a plant availability of 90 percent.
Gas Revenue
Appendix A 1
-------
This analysis assumes an average heat content of 980 Btu per scf for the sales gas. The
assumed market price is $2.00 per mmBtu and the transportation cost paid to the pipeline is
$0.30 per mmBtu, for a net revenue of $1.70 per mmBtu which is then escalated at three
percent per year after year one. The mine's share of the gross gas revenue after a 12.5
percent royalty is 87.5 percent.
Sales Gas Specifications
1. Solids Free of
2. Oxygen 10ppm
3. Nitrogen* Max. 3 percent
4. Carbon Dioxide* Max. 3 percent
5. Hydrogen Sulfide 1/4 Grain/100
6. Total Sulfur 20 Grains/100
7. Liquids Free of
8. Water Vapor 7 Ibs/mmscf
9. Hydrocarbon Dew Point 15 degrees F @ 100-1000 psi
10. Heating Value Min. 980 Btu/scf
11. Temperature Max. 120 F
12. Delivery Pressure 100-800psig
* Total Inerts (Combined) Max. 3 percent
Limits of Analysis
Since the primary intent of this analysis is to compare enrichment cases with different flows and
qualities, the "borders" of the physical plant to be studied were narrowed somewhat to include
only the enrichment system and a modest delivery configuration. The model assumes that the
mine would already have in place a series of gob wells with low pressure blowers and some
piping. It would be a small cost for most mines to complete this gathering system, and that cost
fits within the contingency. Therefore, sunk costs are original well installation costs plus the
costs of installing new wells during the project. Also gob well maintenance service that would
be required anyway does not enter into this analysis. The model further assumes that the
enrichment plant would be close to the gathering system outlet so there will be no additional
gathering costs (except in the break-even analysis, Figure 5, which compares two smaller
plants each located at separated mines with a larger plant). The delivery system consists of a
right-of-way (ROW), a one mile pipe (assuming a 6 inch 250 psi shallow buried pipe), a 600 psi
sales compressor, a metering station, and an interconnection with a natural gas pipeline totaling
$150,000. Some actual interconnections may require pressures of 1000 or 1200 psi, and the
additional cost of injecting at 1200 psi v. 600 is in the range of $0.20 per mmBtu.
Capitalization
For the sake of simplicity the model assumes a 100 percent equity case (i.e. with no project
debt). While a project such as this could raise several types of financing and could use
leverage to increase profit and decrease the impact on a mine operator's balance sheet, it
would be difficult to depict a debt structure that would be applicable to all. For the convenience
Appendix A
-------
of a potential developer there are lines in the Cash Flow Analyses left open to calculate the
impact of debt interest payments and principal repayments on annual cash flow.
Depreciation
A depreciation calculation is necessary to predict federal and state income taxes. This analysis
is presented "pre-tax" (see the discussion on taxes below), so depreciation would not need to
be analyzed. However, the model included it for those that wish to refine the estimates by
applying their own tax situation to the project.
The majority of tangible capital costs follow the Modified Accelerated Cost Recovery System to
calculate a depreciation allowance. This analysis used a seven year recovery period with the
half year convention, 200 percent declining balance method, and no salvage value. Pipeline
and ROW depreciation is straight line over a fifteen year useful life. The depreciation
allowances stretch over the first eight years of the project using the following percentages of
depreciable costs: 14.29, 24.49, 17.49, 12.49, 8.93, 8.92, 8.93, and 4.46 percent.
Operating Expenses
Operating expenses are direct and indirect costs associated with field operations and
maintenance of the enrichment system, compressors, and delivery system: Costs include
direct and supervisory labor, labor benefits and expenses, supplies, fuel and utilities, repair
labor and expense, and other direct and indirect costs. Some of the operating expense data
came from the system vendors; others, such as maintenance labor and materials, and local
taxes and insurance, appear as percentages of plant cost. Personnel assumptions are one full
time operator for all cases except cryogenics plants where one and one quarter operator would
be needed. The model accounts for supervision labor and overheads as a standard override on
labor. Operating expenses also escalate at three percent for the life of the project.
Federal and State Taxes
The analyses are all pre-tax for simplicity and because of the difficulty of selecting a
representative average tax situation for each mine. As no taxes were figured, no
tax credits such as depletion allowances or non-conventional fuel tax credits (Section 29
credits) appear in the analysis. In the case of Section 29 credits, there will be fewer and fewer
mine operators that will be able to take advantage of them as time passes.
Miscellaneous Taxes
Each case assumes a five percent severance tax on the value of all severed minerals (in this
case the mine's share of the methane value) and an ad valorem tax at a rate of three percent of
the mine's share of the methane. This is similar to amounts that would be paid in West Virginia.
Appendix A
-------
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Technical and Economic Assessment of Potential to
Upgrade Gob Gas to Pipeline Quality
APPENDIX B - COST ANALYSIS
B.1 Unit Cost Analysis: Tables 1.1 through 1.20
B.2 Cash Flow Statements: Tables 2.1 through 2.3
-------
-------
Table 1.1 Cost Comparison - 3 mmscfd, 50% Methane
Gas Composition And Flow Rate
Methane
Nitrogen
C02
Oxygen
Water
Gob Gas Flow Rate (Gross) mmscfd
Inlet Gas
50.00%
37.60%
3.00%
9.40%
Saturated
3
Outlet Gas
97.00%
3.00%
0.00%
0.00%
Dry
Technology
Sales Flow Calculations
Gas Usage For Compressors
Sales Gas Flow - mmscfd
mmBtu/y @ 980 Btu/scf, 90% on-line
Capital Costs (M$)
NRU
Deoxygenation
CO2 Removal
Water Removal
Process Compression
Sales Compression
TOTAL DIRECT PLANT
Auxiliary Costs (1 0%)
Install/startup (15%)
Contingency (10%)
Total Capital Cost
Ann. Cap. Recovery -10yr, 25% bef tax
OPERATING COSTS (M$/YR)
Consumables
Utilities
Oper Labor With Benefits
Supv & Overheads
Maint. Materials - 2% direct plant
Maint. Labor - 3% direct plant
Local Taxes/ Ins. - 1.5% direct plant
TOTAL OPERATING COST
TOTAL ANNUAL COST
Low End
0.48
1.17
376,658
1,230
487
150
40
574
145
2,626
263
394
263
-3,545
993
15
30
40
50
53
79
39
266
1,259
High End
0.44
1.27
408,851
1,590
696
200
40
550
120
3,196
320
479
320
4,315
1,208
35
35
40
50
64
96
48
368
1,576
Gas Cost: $/mmBtu 3.34 3.85
*Blended PSA, cryogenic, and solvent absorption costs determine low end and high end costs.
"Low End" technology achieves lower methane recovery and requires higher compression costs.
Appendix B
-------
Table 1.2 Cost Comparison - 3 mmscfd, 60% Methane
Gas Composition And Flow Rate
Methane
Nitrogen
CO2
Oxygen
Water
Gob Gas Flow Rate (G>ross) mmscfd
Inlet Gas
60.00%
29.23%
3.00%
7.77%
Saturated
3
Outlet Gas
97.00%
3.00%
0.00%
0.00%
Dry
Technology
Sales Flow Calculations
Gas Usage For Compressors
Sales Gas Flow - mmscfd
mmBtu/y @ 980 Btu/scf, 90% on-line
Capital Costs (M$)
NRU
Deoxygenation
CO2 Removal
Water Removal
Process Compression
Sales Compression
TOTAL DIRECT PLANT
Auxiliary Costs (10%)
Install/startup (15%)
Contingency (1 0%)
Total Capital Cost
Ann. Cap. Recovery -10yr, 25% bef tax
OPERATING COSTS (M$/YR)
Consumables
Utilities
Oper Labor With Benefits
Supv & Overheads
Maint. Materials - 2% direct plant
Maint. Labor - 3% direct plant
Local Taxes/ Ins. - 1.5% direct plant
TOTAL OPERATING COST
TOTAL ANNUAL COST
Low End
0.43
1.43
460,360
1,130
403
150
40
526
166
2,414
241
362
241
3,259
913
15
30
40
50
48
72
36
256
1,168
High End
0.4
1.54
495,772
1,490
576
200
40
509
143
2,958
296
444
296
3,993
1,118
35
35
40
50
59
89
44
352
1,470
Gas Cost: $/mmBtu 2.54 2.97
*Blended PSA, cryogenic, and solvent absorption costs determine low end and high end costs.
"Low End" technology achieves lower methane recovery and requires higher compression costs.
Appendix B
-------
Table 1.3 Cost Comparison - 3 mmscfd, 70% Methane
Gas Composition And Flow Rate
Methane
Nitrogen
C02
Oxygen
Water
Gob Gas Flow Rate (Gross) mmscfd
Inlet Gas
70.00%
21 .60%
3.00%
5.40%
Saturated
3
Outlet Gas
97.00%
3.00%
0.00%
0.00%
Dry
Technology
Sales Flow Calculations
Gas Usage For Compressors
Sales Gas Flow - mmscfd
mmBtu/y @ 980 Btu/scf, 90% on-line
Capital Costs (M$)
NRU
Deoxygenation
CO2 Removal
Water Removal
Process Compression
Sales Compression
TOTAL DIRECT PLANT
Auxiliary Costs (1 0%)
Install/startup (15%)
Contingency (1 0%)
Total Capital Cost
Ann. Cap. Recovery -10yr, 25% bef tax
OPERATING COSTS (M$/YR)
Consumables
Utilities
Oper Labor With Benefits
Supv & Overheads
Maint. Materials - 2% direct plant
Maint. Labor - 3% direct plant
Local Taxes/ Ins. - 1.5% direct plant
TOTAL OPERATING COST
TOTAL ANNUAL COST
Low End
0.38
1.70
547,281
1,030
280
150
40
477
190
2,167
217
325
217
2,925
819
15
30
40
50
43
65
32
243
1,062
High End
0.36
1.83
589,132
1,390
400
200
40
474
184
2,688
269
403
269
3,629
1,016
35
35
40
50
54
81
40
335
1,351
Gas Cost: $/mmBtu 1 .94 2.29
*Blended PSA, cryogenic, and solvent absorption costs determine low end and high end costs.
"Low End" technology achieves lower methane recovery and requires higher compression costs.
Appendix B
-------
Table 1.4 Cost Comparison - 3 mmscfd, 85% Methane
Gas Composition And Flow Rate
Methane
Nitrogen
CO2
Oxygen
Water
Gob Gas Flow Rate (Gross) mmscfd
Technology
Sales Flow Calculations
Gas Usage For Compressors
Sales Gas Flow - mmscfd
mmBtu/y @ 980 Btu/scf, 90% on-line
Capital Costs (M$)
NRU
Deoxygenation
CO2 Removal
Water Removal
F'rocess Compression
Sales Compression
TOTAL DIRECT PLANT
Auxiliary Costs (1 0%)
Install/startup (15%)
Contingency (10%)
Total Capital Cost
Ann. Cap. Recovery -10yr, 25% bef tax
OPERATING COSTS (M$/YR)
Consumables
Utilities
Oper Labor With Benefits
Supv & Overheads
Maint. Materials - 2% direct plant
Maint. Labor - 3% direct plant
Local Taxes/ Ins. - 1 .5% direct plant
TOTAL OPERATING COST
TOTAL ANNUAL COST
Inlet Gas
85.00%
10.00%
3.00%
2.00%
Saturated
3
Low End
0.30
2.13
685,711
1,030
280
150
40
430
232
2,162
216
324
216
2,919
817
15
30
40
50
43
65
32
243
1,060
Outlet Gas
97.00%
3.00%
0.00%
0.00%
Dry
High End
0.3
2.27
730,781
1 ,200
330
150
40
429
225
2,374
237
356
237
3,205
897
35
35
40
50
47
71
36
314
1,212
Gas Cost: $/mmBtu 1 .55 1 .66
*Blended PSA, cryogenic, and solvent absorption costs determine low end and high end costs.
"Low End" technology achieves lower methane recovery and requires higher compression costs.
Appendix B
-------
Table 1.5 Cost Comparison - 3 mmscfd, 90% Methane
Gas Composition And Flow Rate
Methane
Nitrogen
CO2
Oxygen
Water
Gob Gas Flow Rate (Gross) mmscfd
Inlet Gas
90.00%
6.40%
2.00%
1 .60%
Saturated
3
Outlet Gas
97.00%
3.00%
0.00%
0.00%
Dry
Technology
Sales Flow Calculations
Gas Usage For Compressors
Sales Gas Flow - mmscfd
mmBtu/y @ 980 Btu/scf, 90% on-line
Capital Costs (M$)
NRU
Deoxygenation
CO2 Removal
Water Removal
Process Compression
Sales Compression
TOTAL DIRECT PLANT
Auxiliary Costs (10%)
Install/startup (15%)
Contingency (10%)
Total Capital Cost
Ann. Cap. Recovery -10yr, 25% bef tax
OPERATING COSTS (M$/YR)
Consumables
Utilities
Oper Labor With Benefits
Supv & Overheads
Maint. Materials - 2% direct plant
Maint. Labor - 3% direct plant
Local Taxes/ Ins. - 1.5% direct plant
TOTAL OPERATING COST
TOTAL ANNUAL COST
Low End
0.28
2.27
730,781
1,030
280
150
40
405
248
2,153
215
323
215
2,907
814
15
30
40
50
43
65
32
243
1,057
High End
0.28
2.42
779,071
1,200
330
150
40
406
240
2,366
237
355
237
3,194
894
35
35
40
50
47
71
35
314
1,208
Gas Cost: $/mmBtu 1.45 1.55
*Blended PSA, cryogenic, and solvent absorption costs determine low end and high end costs.
"Low End" technology achieves lower methane recovery and requires higher compression costs.
Appendix B
-------
Table 1.6 Cost Comparison - 4 mmscfd, 50% Methane
Gas Composition And Flow Rate
Methane
Nitrogen
CO2
Oxygen
Water
Gob Gas Flow Rate (Gross) mmscfd
Inlet Gas
50.00%
37.60%
3.00%
9.40%
Saturated
4 available
3 inlet cap
Outlet Gas
97.00%
3.00%
0.00%
0.00%
Dry
Technology
Sales Flow Calculations
Gas Usage For Compressors
Sales Gas Flow - mmscfd
mmBtu/y @ 980 Btu/scf, 90% on-line
Capital Costs (M$)
NRU
Deoxygenation
CO2 Removal
Water Removal
Process Compression
Sales Compression
TOTAL DIRECT PLANT
Auxiliary Costs (10%)
Install/startup (15%)
Contingency (10%)
Total Capital Cost
Ann. Cap. Recovery -10yr, 25% bef tax
OPERATING COSTS (M$/YR)
Consumables
Utilities
Oper Labor With Benefits
Supv & Overheads
Maint. Materials - 2% direct plant
Maint. Labor - 3% direct plant
Local Taxes/ Ins. - 1 .5% direct plant
TOTAL OPERATING COST
TOTAL ANNUAL COST
Low End
0.56
1.39
447,483
1,230
487
150
40
684
179
2,770
277
416
277
3,740
1,047
15
30
40
50
55
83
42
274
1,321
High End
0.5197
1.48
476,456
1,590
696
200
40
654
169
3,349
335
502
335
4,521
1,266
35
35
40
50
67
100
50
378
1,644
Gas Cost: $/mmBtu 2.95 3.45
*Blended PSA, cryogenic, and solvent absorption costs determine low end and high end costs.
"Low End" technology achieves lower methane recovery and requires higher compression costs.
Appendix B
-------
Table 1.7 Cost Comparison - 4 mmscfd, 60% Methane
Gas Composition And Flow Rate
Methane
Nitrogen
CO2
Oxygen
Water
Gob Gas Flow Rate (Gross) mmscfd
Inlet Gas
60.00%
29.23%
3.00%
7.77%
Saturated
4 available
3 inlet cap
Outlet Gas
97.00%
3.00%
0.00%
0.00%
Dry
Technology
Sales Flow Calculations
Gas Usage For Compressors
Sales Gas Flow - mmscfd
mmBtu/y @ 980 Btu/scf, 90% on-line
Capital Costs (M$)
NRU
Deoxygenation
CO2 Removal
Water Removal
Process Compression
Sales Compression
TOTAL DIRECT PLANT
Auxiliary Costs (10%)
Install/startup (15%)
Contingency (10%)
Total Capital Cost
Ann. Cap. Recovery -10yr, 25% bef tax
OPERATING COSTS (M$/YR)
Consumables
Utilities
Oper Labor With Benefits
Supv & Overheads
Maint. Materials - 2% direct plant
Maint. Labor - 3% direct plant
Local Taxes/ Ins. - 1 .5% direct plant
TOTAL OPERATING COST
TOTAL ANNUAL COST
Low End
0.50
1.67
537,623
1,130
403
150
40
615
199
2,536
254
380
254
3,424
959
15
30
40
50
51
76
38
262
1,221
High End
0.4651
1.78
573,035
1,490
576
200
40
601
189
3,096
310
464
310
4,179
1,170
35
35
40
50
62
93
46
361
1,531
Gas Cost: $/mmBtu 2.27 2.67
*Blended PSA, cryogenic, and solvent absorption costs determine low end and high end costs.
"Low End" technology achieves lower methane recovery and requires higher compression costs.
Appendix B
-------
Table 1.8 Cost Comparison - 4 mmscfd, 70% Methane
Gas Composition And Flow Rate
Methane
Nitrogen
CO2
Oxygen
Water
Gob Gas Flow Rate (Gross) mmscfd
Inlet Gas
70.00%
21.60%
3.00%
5.40%
Saturated
4 available
3 inlet cap
Outlet Gas
97.00%
3.00%
0.00%
0.00%
Dry
Technology
Sales Flow Calculations
Gas Usage For Compressors
Sales Gas Flow - mmscfcl
mmBtu/y @ 980 Btu/scf, 90% on-line
Capital Costs (M$)
NRU
Deoxygenation
CO2 Removal
Water Removal
Process Compression
Sales Compression
TOTAL DIRECT PLANT
Auxiliary Costs (10%)
Install/startup (15%)
Contingency (10%)
Total Capital Cost
Ann. Cap. Recovery -10yr, 25% bef tax
OPERATING COSTS (M$/YR)
Consumables
Utilities
Oper Labor With Benefits
Supv & Overheads
Maint. Materials - 2% direct plant
Maint. Labor - 3% direct plant
Local Taxes/ Ins. - 1 .5% direct plant
TOTAL OPERATING COST
TOTAL ANNUAL COST
Low End
0.43
1.95
627,764
1,030
280
150
40
548
220
2,268
227
340
227
3,062
857
15
30
40
50
45
68
34
248
1,106
High End
0.4105
2.08
669,614
1,390
400
200
40
548
210
2,789
279
418
279
3,765
1,054
35
35
40
50
56
84
42
341
1,395
Gas Cost: $/mmBtu 1.76 2.08
*Blended PSA, cryogenic, and solvent absorption costs determine low end and high end costs.
"Low End" technology achieves lower methane recovery and requires higher compression costs.
Appendix B
-------
Table 1.9 Cost Comparison - 4 mmscfd, 85% Methane
Gas Composition And Flow Rate
Methane
Nitrogen
CO2
Oxygen
Water
Gob Gas Flow Rate (Gross) mmscfd
Inlet Gas
85.00%
10.00%
3.00%
2.00%
Saturated
4 available
3 inlet cap
Outlet Gas
97.00%
3.00%
0.00%
0.00%
Dry
Technology
Sales Flow Calculations
Gas Usage For Compressors
Sales Gas Flow - mmscfd
mmBtu/y @ 980 Btu/scf, 90% on-line
Capital Costs (M$)
NRU
Deoxygenation
CO2 Removal
Water Removal
Process Compression
Sales Compression
TOTAL DIRECT PLANT
Auxiliary Costs (10%)
Install/startup (15%)
Contingency (10%)
Total Capital Cost
Ann. Cap. Recovery -10yr, 25% bef tax
OPERATING COSTS (M$/YR)
Consumables
Utilities
Oper Labor With Benefits
Supv & Overheads
Maint. Materials - 2% direct plant
Maint. Labor - 3% direct plant
Local Taxes/ Ins. - 1 .5% direct plant
TOTAL OPERATING COST
TOTAL ANNUAL COST
Low End
0.33
2.37
762,974
1,030
280
150
40
471
258
2,229
223
334
223
3,009
842
15
30
40
50
45
67
33
246
1,089
High End
0.33
2.52
81 1 ,264
1,390
330
150
40
498
248
2,656
266
398
266
3,586
1,004
35
35
40
50
53
80
40
333
1,337
Gas Cost: $/mmBtu 1 .43 1 .65
*Blended PSA, cryogenic, and solvent absorption costs determine low end and high end costs.
"Low End" technology achieves lower methane recovery and requires higher compression costs.
Appendix B
-------
Table 1.10 Cost Comparison - 4 mmscfd, 90% Methane
Gas Composition And Flow Rate
Methane
Nitrogen
CO2
Oxygen
Water
Gob Gas Flow Rate (Gross) mmscfd
Inlet Gas
90.00%
6.40%
2.00%
1 .60%
Saturated
4 available
3 inlet cap
Outlet Gas
97.00%
3.00%
0.00%
0.00%
Dry
Technology
Sales Flow Calculations
Gas Usage For Compressors
Sales Gas Flow - mmscfd
mmBtu/y @ 980 Btu/scf, 90% on-line
Capital Costs (M$)
NRU
Deoxygenation
CO2 Removal
Water Removal
Process Compression
Sales Compression
TOTAL DIRECT PLANT
Auxiliary Costs (10%)
Install/startup (15%)
Contingency (1 0%)
Total Capital Cost
Ann. Cap. Recovery -10yr, 25% bef tax
OPERATING COSTS (M$/YR)
Consumables
Utilities
Oper Labor With Benefits
Supv & Overheads
Maint. Materials - 2% direct plant
Maint. Labor - 3% direct plant
Local Taxes/ Ins. - 1 .5% direct plant
TOTAL OPERATING COST
TOTAL ANNUAL COST
Low End
0.30
2.51
808,044
1,030
280
150
40
446
272
2,218
222
333
222
2,994
838
15
30
40
50
44
67
33
246
1,084
High End
0.3
2.67
859,553
"1,200
280
150
40
468
262
2,400
240
360
240
3,240
907
35
35
40
50
48
72
36
316
1,223
Gas Cost: $/mmBtu 1 .34 1 .42
*Blended PSA, cryogenic, and solvent absorption costs determine low end and high end costs.
"Low End" technology achieves lower methane recovery and requires higher compression costs.
Appendix B
10
-------
Table 1.11 Cost Comparison - 5 mmscfd, 50% Methane
Gas Composition And Flow Rate
Methane
Nitrogen
CO2
Oxygen
Water
Gob Gas Flow Rate (Gross) mmscfd
Technology
Sales Flow Calculations
Gas Usage For Compressors
Sales Gas Flow - mmscfd
mmBtu/y @ 980 Btu/scf, 90% on-line
Capital Costs (M$)
NRU
Deoxygenation
CO2 Removal
Water Removal
Process Compression
Sales Compression
TOTAL DIRECT PLANT
Auxiliary Costs (10%)
Install/startup (15%)
Contingency (10%)
Total Capital Cost
Ann. Cap. Recovery -10yr, 25% bef tax
OPERATING COSTS (M$/YR)
Consumables
Utilities
Oper Labor With Benefits
Supv & Overheads
Maint. Materials - 2% direct plant
Maint. Labor - 3% direct plant
Local Taxes/ Ins. - 1 .5% direct plant
TOTAL OPERATING COST
TOTAL ANNUAL COST
Inlet Gas
50.00%
37.60%
3.00%
9.40%
Saturated
5
Low End
'0.71
1.99
640,641
1,671
696
200
50
1,006
219
3,842
384
576
;384
5,187
1,452
30
50
40
50
77
115
58
362
1,815
Outlet Gas
97.00%
3.00%
0.00%
0.00%
Dry
High End
0.7081
2.12
682,492
2,160
870
200
50
939
224
4,444
444
667
444
5,999
1,680
60
60
40
50
89
133
67
499
2,179
Gas Cost: $/mmBtu 2.83 3.19
*Blended PSA, cryogenic, and solvent absorption costs determine low end and high end costs.
"Low End" technology achieves lower methane recovery and requires higher compression costs.
Appendix B
11
-------
Table 1.12 Cost Comparison - 5 mmscfd, 60% Methane
Gas Composition And Flow Rate
Methane
Nitrogen
CO2
Oxygen
Water
Gob Gas Flow Rate (Gross) mmscfd
Inlet Gas
60.00%
29.23%
3.00%
7.77%
Saturated
5
Outlet Gas
97.00%
3.00%
0.00%
0.00%
Dry
Technology
Sales Flow Calculations
Gas Usage For Compressors
Sales Gas Flow - mmscfd
mmBtu/y @ 980 Btu/scf, 90% on-line
Capital Costs (M$)
NRU
Deoxygenation
CO2 Removal
Water Removal
Process Compression
Sales Compression
TOTAL DIRECT PLANT
Auxiliary Costs (10%)
Install/startup (15%)
Contingency (10%)
Total Capital Cost
Ann. Cap. Recovery -10yr, 25% bef tax
OPERATING COSTS (M$/YR)
Consumables
Utilities
Oper Labor With Benefits
Supv & Overheads
Maint. Materials - 2% direct plant
Maint. Labor - 3% direct plant
Local Taxes/ Ins. - 1 .5% direct plant
TOTAL OPERATING COST
TOTAL ANNUAL COST
Low End
0.63
2.43
782,290
1,535
576
200
50
892
257
3,509
351
526
351
4,737
1,326
30
50
40
50
70
105
53
345
1,672
High End
0.63502
2.59
833,799
2,024
719
200
50
868
260
4,121
412
618
412
5,564
1,558
60
60
40
50
82
124
62
478
2,036
Gas Cost: $/mmBtu 2.14 2.44
*Blended PSA, cryogenic, and solvent absorption costs determine low end and high end costs.
"Low End" technology achieves lower methane recovery and requires higher compression costs.
Appendix B
12
-------
Table 1.13 Cost Comparison - 5 mmscfd, 70% Methane
Gas Composition And Flow Rate
Methane
Nitrogen
CO2
Oxygen
Water
Gob Gas Flow Rate (Gross) mmscfd
Inlet Gas
70.00%
21.60%
'3.00%
5.40%
Saturated
5
Outlet Gas
97.00%
3.00%
0.00%
0.00%
Dry
Technology
Sales Flow Calculations
Gas Usage For Compressors
Sales Gas Flow - mmscfd
mmBtu/y @ 980 Btu/scf, 90% on-line
Capital Costs (M$)
NRU
Deoxygenation
CO2 Removal
Water Removal
Process Compression
Sales Compression
TOTAL DIRECT PLANT
Auxiliary Costs (10%)
Install/startup (15%)
Contingency (10%)
Total Capital Cost
Ann. Cap. Recovery -10yr, 25% bef tax
OPERATING COSTS (M$/YR)
Consumables
Utilities
Oper Labor With Benefits
Supv & Overheads
Maint. Materials - 2% direct plant
Maint. Labor - 3% direct plant
Local Taxes/ Ins. - 1 .5% direct plant
TOTAL OPERATING COST
TOTAL ANNUAL COST
Low End
0.56
2.88
927,158
1,399
400
200
50
790
301
3,141
314
471
314
4,240
1,187
30
50
40
50
63
94
47
327
1,514
High End
0.56194
3.07
988,325
1,889
500
200
50
802
301
3,741
374
561
374
5,051
1,414
60
60
40
50
75
112
56
453
1,867
Gas Cost: $/mmBtu 1 .63 1 .89
*Blended PSA, cryogenic, and solvent absorption costs determine low end and high end costs.
"Low End" technology achieves lower methane recovery and requires higher compression costs.
Appendix B
13
-------
Table 1.14 Cost Comparison - 5 mmscfd, 85% Methane
Gas Composition And Flow Rate
Methane
Nitrogen
C02
Oxygen
Water
Gob Gas Flow Rate (Gross) mmscfd
mlet Gas
85.00%
10.00%
3.00%
2.00%
Saturated
5
Outlet Gas
97.00%
3.00%
0.00%
0.00%
Dry
Technology
Sales Flow Calculations
Gas Usage For Compressors
Sales Gas Flow - mmscfd
mmBtu/y @ 980 Btu/scf, 90% on-line
Capital Costs (M$)
NRU
Deoxygenation
CO2 Removal
Water Removal
Process Compression
Sales Compression
TOTAL DIRECT PLANT
Auxiliary Costs (10%)
Install/startup (15%)
Contingency (10%)
Total Capital Cost
Ann. Cap. Recovery -10yr, 25% bef tax
OPERATING COSTS (M$/YR)
Consumables
Utilities
Oper Labor With Benefits
Supv & Overheads
Maint. Materials - 2% direct plant
Maint. Labor - 3% direct plant
Local Taxes/ Ins. - 1 .5% direct plant
TOTAL OPERATING COST
TOTAL ANNUAL COST
Low End
0.45
3.59
1,155,729
1,399
400
200
50
659
383
3,092
309
464
309
4,174
1,169
30
50
40
50
62
93
46
325
1,493
High End
0.45232
3.83
1 ,232,992
1,889
460
200
50
713
375
3,686
369
553
369
4,977
1,393
60
60
40
50
74
111
55
450
1,843
Gas Cost: $/mmBtu 1 .29 1 .49
*Blended PSA, cryogenic, and solvent absorption costs determine low end and high end costs.
"Low End" technology achieves lower methane recovery and requires higher compression costs.
Appendix B
14
-------
Table 1.15 Cost Comparison - 5 mmscfd, 90% Methane
Gas Composition And Flow Rate
Methane
Nitrogen
CO2
Oxygen
Water
Gob Gas Flow Rate (Gross) mmscfd
Inlet Gas
90.00%
6.40%
2.00%
1 .60%
Saturated
5
Outlet Gas
97.00%
3.00%
0.00%
0.00%
Dry
Technology
Sales Flow Calculations
Gas Usage For Compressors
Sales Gas Flow - mmscfd
mmBtu/y @ 980 Btu/scf, 90% on-line
Capital Costs (M$)
NRU
Deoxygenation
CO2 Removal
Water Removal
Process Compression
Sales Compression
TOTAL DIRECT PLANT
Auxiliary Costs (10%)
Install/startup (15%)
Contingency (10%)
Total Capital Cost
Ann. Cap. Recovery -10yr, 25% bef tax
OPERATING COSTS (M$/YR)
Consumables
Utilities
Oper Labor With Benefits
Supv & Overheads
Maint. Materials - 2% direct plant
Maint. Labor - 3% direct plant
Local Taxes/ Ins. - 1 .5% direct plant
TOTAL OPERATING COST
TOTAL ANNUAL COST
Low End
0.41
3.83
1,232,992
1,399
400
200
50
621
415
3,085
309
463
309
4,165
1,166
30
50
40
50
62
93
46
324
1,491
High End
0.41578
4.08
1,313,474
1,889
400
200
50
685
404
3,628
363
544
363
4,897
1,371
60
60
40
50
73
109
54
446
1,817
Gas Cost: $/mmBtu 1.21 1.38
*Blended PSA, cryogenic, and solvent absorption costs determine low end and high end costs.
"Low End" technology achieves lower methane recovery and requires higher compression costs.
Appendix B
15
-------
Table 1.16 Cost Comparison - 6 mmscfd, 50% Methane
Gas Composition And Flow Rate
Methane
Nitrogen
CO2
Oxygen
Water
Gob Gas Flow Rate (Gross) mmscfd
Technology
Sales Flow Calculations
Gas Usage For Compressors (1)
Sales Gas Flow - mrnscfd
mmBtu/y @ 980 Btu/scf, 90% on-line
Capital Costs (M$)
NRU
Deoxygenation
CO2 Removal
Water Removal
Process Compression
Sales Compression
TOTAL DIRECT PLANT
Auxiliary Costs (10%)
Install/startup (15%)
Contingency (10%)
Total Capital Cost
Ann. Cap. Recovery -10yr, 25% bef tax
OPERATING COSTS (M$/YR)
Consumables
Utilities
Oper Labor With Benefits
Supv & Overheads
Maint. Materials - 2% direct plant
Maint. Labor - 3% direct plant
Local Taxes/ Ins. - 1 .5% direct plant
TOTAL OPERATING COST
TOTAL ANNUAL COST
Gas Cost: $/mmBtu
Inlet Gas
50.00%
37.60%
3.00%
9.40%
Saturated
6 available
5 inlet cap
Low End
0.81
2.32
746,878
1671
696
200
50
1106
272
3995
400
599
400
5393
1510
30
50
40
50
80
120
60
370
1880
2.52
Outlet Gas
97.00%
3.00%
0.00%
0.00%
Dry
High End
0.81
2.47
795,167
2160
870
200
50
1040
268
4589
459
688
459
6195
1735
60
60
40
50
92
138
69
508
2243
2.82
"Blended PSA, cryogenic, and solvent absorption costs determine low end and high end costs.
"Low End" technology achieves lower methane recovery and requires higher compression costs.
Appendix B
16
-------
Table 1.17 Cost Comparison - 6 mmscfd, 60% Methane
Gas Composition And Flow Rate
Methane
Nitrogen
CO2
Oxygen
Water
Gob Gas Flow Rate (Gross) mmscfd
Technology
Sales Flow Calculations
Gas Usage For Compressors (1)
Sales Gas Flow - mmscfd
mmBtu/y @ 980 Btu/scf, 90% on-line
Capital Costs (MS)
NRU
Deoxygenation
CO2 Removal
Water Removal
Process Compression
Sales Compression
TOTAL DIRECT PLANT
Auxiliary Costs (10%)
Install/startup (15%)
Contingency (10%)
Total Capital Cost
Ann. Cap. Recovery -10yr, 25% bef tax
OPERATING COSTS (M$/YR)
Consumables
Utilities
Oper Labor With Benefits
Supv & Overheads
Maint. Materials - 2% direct plant
Maint. Labor - 3% direct plant
Local Taxes/ Ins. - 1 .5% direct plant
TOTAL OPERATING COST
TOTAL ANNUAL COST
Gas Cost: $/mmBtu
Inlet Gas
60.00%
29.23%
3.00%
7.77%
Saturated
6 available
5 inlet cap
Low End
0.72
2.78
894,965
1535
576
200
50
987
309
3656
366
548
366
4936
1382
30
50
40
50
73
110
55
353
1735
1.94
Outlet Gas
97.00%
3.00%
0.00%
0.00%
Dry
High End
0.72
2.97
956,132
2024
719
200
50
963
302
4259
426
639
426
5750
1610
60
60
40
50
85
128
64
487
2097
2.19
'Blended PSA, cryogenic, and solvent absorption costs determine low end and high end costs.
"Low End" technology achieves lower methane recovery and requires higher compression costs.
Appendix B
17
-------
Table 1.18 Cost Comparison - 6 mmscfd, 70% Methane
Gas Composition And Flow Rate
Methane
Nitrogen
CO2
Oxygen
Water
Gob Gas Flow Rate (Gross) mmscfd
Technology
Inlet Gas
70.00%
21.60%
' 3.00%
5.40%
Saturated
6 available
5 inlet cap
Low End
Sales Flow Calculations
Gas Usage For Compressors (1)
Sales Gas Flow - mrnscfd
mmBtu/y @ 980 Btu/scf, 90% on-line
Capital Costs (M$)
NRU
Deoxygenation
CO2 Removal
Water Removal
Process Compression
Sales Compression
TOTAL DIRECT PLANT
Auxiliary Costs (10%)
Install/startup (15%)
Contingency (10%)
Total Capital Cost
Ann. Cap. Recovery -10yr, 25% bef tax
OPERATING COSTS (M$/YR)
Consumables
Utilities
Oper Labor With Benefits
Supv & Overheads
Maint. Materials - 2%, direct plant
Maint. Labor - 3% direct plant
Local Taxes/ Ins. - 1 .5% direct plant
TOTAL OPERATING COST
TOTAL ANNUAL COST
Gas Cost: $/mmBtu
0.63
3.25
1,046,273
1399
400
200
50
880
351
3280
328
492
328
4428
1240
30
50
40
50
66
98
49
334
1574
1.50
Outlet Gas
97.00%
3.00%
0.00%
0.00%
Dry
High End
0.63
3.46
1,113,878
1889
500
200
50
892
340
3871
387
581
387
5225
1463
60
60
40
50
77
116
58
462
1925
1.73
*Blended PSA, cryogenic, and solvent absorption costs determine low end and high end costs.
"Low End" technology achieves lower methane recovery and requires higher compression costs.
Appendix B
18
-------
Table 1.19 Cost Comparison - 6 mmscfd, 85% Methane
Gas Composition And Flow Rate
Methane
Nitrogen
CO2
Oxygen
Water
Gob Gas Flow Rate (Gross) mmscfd
Technology
Sales Flow Calculations
Gas Usage For Compressors (1)
Sales Gas Flow - mmscfd
mmBtu/y @ 980 Btu/scf, 90% on-line
Capital Costs (M$)
NRU
Deoxygenation
CO2 Removal
Water Removal
Process Compression
Sales Compression
TOTAL DIRECT PLANT
Auxiliary Costs (10%)
Install/startup (15%)
Contingency (10%)
Total Capital Cost
Ann. Cap. Recovery -10yr, 25% bef tax
OPERATING COSTS (M$/YR)
Consumables
Utilities
Oper Labor With Benefits
Supv & Overheads
Maint. Materials - 2% direct plant
Maint. Labor - 3% direct plant
Local Taxes/ Ins. - 1 .5% direct plant
TOTAL OPERATING COST
TOTAL ANNUAL COST
Gas Cost: $/mmBtu
Inlet Gas
85.00%
10.00%
3.00%
2.00%
Saturated
6 available
5 inlet cap
Low End
0.50
3.94
1,268,404
1399
400
200
50
741
425
3216
322
482
322
4341
1216
30
50
40
50
64
96
48
331
1546
1.22
Outlet Gas
97.00%
3.00%
0.00%
0.00%
Dry
High End
0.50
4.21
1 ,355,325
1889
500
200
50
795
412
3845
385
577
385
5191
1453
60
60
40
50
77
115
58
460
1913
1.41
*Blended PSA, cryogenic, and solvent absorption costs determine low end and high end costs.
"Low End technology achieves lower methane recovery and requires higher compression costs.
Appendix B
19
-------
Table 1.20 Cost Comparison - 6 mmscfd, 90% Methane
Gas Composition And Flow Rate
Methane
Nitrogen
CO2
Oxygen
Water
Gob Gas Flow Rate (Gross) mmscfd
Technology
Sales Flow Calculations
Gas Usage For Compressors (1 )
Sales Gas Flow - mrnscfd
mmBtu/y @ 980 Btu/scf, 90% on-line
Capital Costs (M$)
NRU
Deoxygenation
CO2 Removal
Water Removal
Process Compression
Sales Compression
TOTAL DIRECT PLANT
Auxiliary Costs (10%)
Install/startup (15%)
Contingency (10%)
Total Capital Cost
Ann. Cap. Recovery -10yr, 25% bef tax
OPERATING COSTS (M$/YR)
Consumables
Utilities
Oper Labor With Benefits
Supv & Overheads
Maint. Materials - 2% direct plant
Maint. Labor - 3% direct plant
Local Taxes/ Ins. - 1.5% direct plant
TOTAL OPERATING COST
TOTAL ANNUAL COST
Gas Cost: $/mmBtu
Inlet Gas
90.00%
6.40%
2.00%
1 .60%
Saturated
6 available
5 inlet cap
Low End
0.45
4.18
1,345,667
1399
400
200
50
700
453
3203
320
480
320
4324
1211
30
50
40
50
64
96
48
330
1541
1.14
Outlet Gas
97.00%
3.00%
0.00%
0.00%
Dry
High End
0.46
4.45
1,432,589
1889
400
200
50
765
432
3735
374
560
374
5042
1412
60
60
40
50
75
112
56
453
1865
1.30
*Blended PSA, cryogenic, and solvent absorption costs determine low end and high end costs.
"Low End technology achieves lower methane recovery and requires higher compression costs.
Appendix B
20
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-------
-------
Technical and Economic Assessment of Potential to
Upgrade Gob Gas to Pipeline Quality
APPENDIX C - REFERENCES
-------
-------
Technical and Economic Assessment of Potential to
Upgrade Gob Gas to Pipeline Quality
References
1. Echterhoff, L.W. and Pathak, V.K., 1991. Evaluation of Process Costs for Small
Scale Nitrogen Removal from Natural Gas. Topical Report, Gas Research Institute,
GRI-91/0092.
2. James, J. L. Ma, 1991, Comparison of the Mehra Process for Nitrogen Rejection to
a Cryogenic Process for Nitrogen Rejection from Subquality Natural Gas. Topical
Report, Gas Research Institute, GRI-90/0290.
3. Szatny, M. and Wood, G., 1994, Field Test Performance Evaluation of the Mehra
Process for Nitrogen Rejection from Natural Gas. Topical Report, Gas Research
institute, GRI-93/0448.
4. Confidential documents supplied to University of Utah by: Nitrotec Engineering,
Advanced Extraction Technologies, and UOP, 1993.
5. D'Amico, J.S. (President, Nitrotec Engineering Co.), 1996, Latest Developments in
PSA Technology. Paper at Spring 1996 Session of North American Coalbed
Methane Forum.
6. Fisher, Kevin, 1995, Hydrogen Sulfide Scavenging Research Accelerated the Use of
Improved Technologies. Article in Winter 1995/1996 "GasTIPS".
7. Resource Enterprises, Inc., University of Utah Chemical and Fuels Engineering
Department, and Heredy Consultants, 1993, Commercialization of Waste Gob Gas
and Methane Produced in Conjunction with Coal Mining Operations. Final Report for
U.S. Department of Energy.
8. Babcock et.al., Bend Research, Inc., 1997, Nitrogen-Removal from Natural Gas
Using Solutions of Transition-Metal Compounds, paper presented at AlChE 1997
Spring National Meeting, March 9-13, Houston, TX.
9. Shirley. A.. Porto. J. and Hawk. E.. 1997. A Demonstration of Methane Recovery
from Coal Mine Gases by Pressure Swing Adsorption. Paper 9721, Presented at the
1997 International Coalbed Methane Symposium, held at the University of Alabama,
Tuscaloosa, AL, May 12-16.
10. Soot, Peet., 1997, NW Fuel Gas Processing Experience with Coal Mine Waste
Methane Streams, unpublished paper, August.
11. EPA, 1996, Feasibility Analysis of Coal Mine Methane Use and Transportation
Options, unpublished draft, Office of Air and Radiation (6202J), Washington, DC,
August.
Appendix C
-------
Technical and Economic Assessment of Potential to
Upgrade Gob Gas to Pipeline Quality
12. EPA, 1996, Finance Opportunities for Coal Mine Methane Projects: A Guide to
Federal Assistance. Office of Air and Radiation (6202J), EPA430-R-95-014
Washington, DC, March.
13. EPA, 1997, A Guide to Financing Coalbed Methane Projects. Office of Air and
Radiation (6202J), EPA430-B-97-001, Washington, DC, January.
14. EPA, 1993, Options for Reducing Methane Emissions Internationally. Volume II:
International Opportunities for Reducing Methane Emissions. Report to Congress.
Office of Air and Radiation, Washington, DC.
Appendix C
-------
Technical and Economic Assessment of Potential to
Upgrade Gob Gas to Pipeline Quality
APPENDIX D - CONTACT INFORMATION
-------
-------
Technical and Economic Assessment of Potential to
Upgrade Gob Gas to Pipeline Quality
Contact List
1. Integrated System Suppliers (Nitrogen Rejection)
1.1 UOP Corporation
Natural Gas Processing
13105 Northwest Freeway
Suite 600
Houston, TX 77040
ATTN: Mr. Ronnie J. Buras, 713 744-2881
1.2 Nitrotec Engineering
16430 Park Ten
Suite 600
Houston, TX 77084
ATTN: Herb Reinhold, 281 398-3879
1.3 Advanced Extraction Technologies, Inc.
2 North Point Drive
Suite 820
Houston, TX 77060
ATTN: Mr. Yuv R. Mehra, 281 447-0571
1.4 Darnell Engineering Corporation
363 N. Sam Houston Parkway East
Suite 640
Houston, TX 77060
ATTN: Mr. Quinton L. Darnell, 713 999-0123
1.5 Schedule A, Inc.
9894 Bissonet
Suite 888
Houston, TX 77036-8229
ATTN: Mr. Pierre E. Lugosch, 713 777-7771
1.6 BOC Group
100 Mountain Avenue
Murray Hill, NJ 07974
ATTN: Dr. Art Shirley, 908 771-6104, Fax 908 771-6113
1.7 BCCK Engineering Inc.
2500 N. Big Spring
Suite 230
Midland, TX 79705
ATTN: Mr. R. Clark Butts, Pres., 915 685-6095
Appendix D
-------
Technical and Economic Assessment of Potential to
Upgrade Gob Gas to Pipeline Quality
2. Nitrogen Rejection - (in development)
2.1 Bend Research, Inc.
64550 Research Road
Bend, OR 97701
ATTN: Mr. David Lyon, 541 382-4100, Fax 541 382-2713
2.2 Gas Separation Technology
1667 Cole Boulevard
Suite 400
Golden, CO 80226
ATTN: Mr. Major W. Seery, 303 232-0658
2.3 Northwest Fuel Development
4064 Orchard Drive
Lake Oswego, OR 97035
ATTN: Peet Soot, Pres., 503 699-9836
3. Oxygen Removal Equipment
3.1 Optimized Process Design
25606 Clay Road
Katy, TX 77493
ATTN: Mr. Chuck DeWees, 281 371-7500
4. Carbon Dioxide Removal Equipment
4.1 Sivalls, Inc.
2200 E. 2nd Street
Odessa, TX 79761
ATTN: Mr. William J. Lawallen, 915 337-3571
5. Other
5.1 Waukesha-Pearce Industries, Inc. (Compressor Manufacturer)
12320 S. Maid
Houston, TX 77035
ATTN: Mr. John R. Burrows, 713 723-1050
5.2 Gas Research Institute (GRI)
8600 W. Bryn Mawr Avenue
Chicago, IL 60631
ATTN: Howard Meyer and Dennis Leppin, 312 399-8100
Appendix D
-------
Technical and Economic Assessment of Potential to
Upgrade Gob Gas to Pipeline Quality
APPENDIX E -
TECHNICAL EVALUATIONS OF ENRICHMENT PROCESSES
-------
-------
Technical and Economic Assessment of Potential to
Upgrade Gob Gas to Pipeline Quality
Technical Evaluations of Enrichment Processes
Prepared by:
Jonggyun Kim and Milind D. Deo
Department of Chemical and Fuels Engineering
University of Utah, Salt Lake City, Utah
Appendix E
-------
Technical and Economic Assessment of Potential to
Upgrade Gob Gas to Pipeline Quality
Contents
INTRODUCTION
PROCESS EVALUATION 1
THE CRYOGENICS NRU 2
LEAN-OIL OR SELECTIVE ABSORPTION PROCESS 4
PRESSURE SWING ADSORPTION PROCESS (PSA) 5
SUMMARY 7
REFERENCES 8
FIGURES (1-7)
TABLES (1-14)
Appendix E
-------
Technical and Economic Assessment of Potential to
Upgrade Gob Gas to Pipeline Quality
Introduction
Coal-mine gob gas usually contains nitrogen, carbon dioxide, oxygen and water vapor, in
addition to methane. Typical pipeline specifications for natural gas allow only four percent
inerts in the gas. Often, the specifications for oxygen (< 10 ppm) are stringent. Thus, the
following processes are necessary for the enrichment of gob gas to pipeline quality.
1. Nitrogen rejection
2. Deoxygenation
3. Carbon dioxide removal
4. Removal of water vapor
Nitrogen rejection is the most difficult and the most expensive component of the gob gas
enrichment technology. Oxygen removal can also be difficult because removal of higher than
1.5 percent oxygen in the feed gas leads to additional problems due to excessive temperatures
in the deoxygenation unit. Also, O2 must be completely removed to meet many pipeline
specifications. The most difficult aspect of all the gob gas enrichment technologies is feed gas
variability both in terms of flow rate and composition. This technical analysis was undertaken to
evaluate the technical feasibility of gob gas enrichment technologies operating under field
conditions. The objective was to define the range of operability of the enrichment technologies
by calculating detailed material and energy balances. These calculations were also expected to
identify if gas flammability might be of concern in any of the process units.
Process Evaluation
The technical evaluations performed on three different integrated processes for the enrichment
of gob gas. The three approaches differed only in terms of their nitrogen rejection units (NRU).
The NRU methods were:
1. Cryogenics
2. The lean oil process or selective absorption
3. Pressure swing adsorption process
The base case evaluations consisted of enriching a 3 mmscfd feed containing the following
gases (by volume): 70 percent methane, 3 percent carbon dioxide, 21.6 percent nitrogen, 5.4
percent oxygen, and saturated with water vapor. Nitrogen, oxygen and carbon dioxide are the
normal contaminants in gob gas streams. The level of carbon dioxide is usually higher in gob
gas than in air because carbon dioxide is a typical constituent of coal seam gas. The carbon
dioxide concentration varies considerably in gob gas from less than one percent to about 10
percent in most mines, even though gases from some mines (particularly, in Australia) have
carbon dioxide concentrations as high as 50 percent. A concentration of 3 percent was
considered "typical" for a number of coal mines and was selected on that basis. The
concentrations of oxygen and nitrogen were in the same proportion as in air.
Appendix E
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Technical and Economic Assessment of Potential to
Upgrade Gob Gas to Pipeline Quality
The feed gas compositions have to be converted to an absolute (wet) basis in order to perform
material and energy balances. The gas composition including water vapor would then be, 67.6
percent methane, 20.9 percent nitrogen, 5.2 percent oxygen, 2.9 percent carbon dioxide and
3.1 percent water vapor. The objective of enrichment was to produce about 97 percent
methane and 3 percent nitrogen in the product stream.
Once the base case comparisons were established, computer simulations were performed at
three other combinations of flow rate and gas quality. This report includes process flow
diagrams for each of the processes along with brief analyses.
The Cryogenics NRU
Figure 1a presents the integrated flow diagram for the cryogenics NRU. A more detailed flow
sheet of only the NRU is shown in Figure 1 b. The feed gas compressor in Figure 1 a actually
consists of two compressors and two intercoolers. Table 1 contains material and enthalpy
specifications for each of the process streams. A process flow diagram and the data in Table 1.
were generated using CHEMCAD, a well-established chemical process simulator developed by
CHEMSTATIONS, Inc., Houston, Texas. The Department of Chemical and Fuels Engineering
at the University of Utah has a special license to use the simulator for educational and research
purposes. The process flow diagram was conceptualized based on process schemes
suggested in reference 1 (GRII, 1991). CHEMCAD simulated the actual distillation process for
the separation of nitrogen and methane using well established chemical engineering separation
calculations. The process concept appears conventional. It should be' noted, however, that
there are a number of process units sequenced together. The concentrations of carbon dioxide
and water are higher at the exit of the deoxygenation unit than the feed to the unit since, in the
deoxygenation unit, methane is combusted to produce carbon dioxide and water. The process
sequencing makes the operation complicated.
The composition of the gas stream at the inlet of the distillation column is about 76 percent
methane and 24 percent nitrogen. Thus, all or most of the oxygen as well as carbon dioxide
and moisture has been removed prior to the distillation step. The decision to remove all oxygen
before the distillation step was made based on earlier sensitivity simulations of the distillation
column (using CHEMCAD) as a single unit. When this study was begun, it was believed that a
significant degree of deoxygenation would be achieved in the distillation process itself. A
CHEMCAD distillation simulation performed in order to verify this claim is shown in Figure 2. In
this simulation, a feed consisting of about six percent oxygen was sent to the distillation column.
When the distillation conditions were adjusted to produce about 95 percent methane in the
product stream, the oxygen content of this gas was still 3.3 percent. It should be noted that
nitrogen rejection of 93 percent was achieved in this separation while an oxygen rejection of
only 55 percent was achieved. Furthermore, the methane concentration changes from about
72 percent at the inlet of the distillation column to about 11 percent at the outlet. Thus, within
the distillation column the gas composition does reach the fiammability limit, if oxygen is not
removed up front. The amine unit for the removal of carbon dioxide from the gas also needs to
precede the cryogenic distillation unit since even small concentrations of carbon dioxide would
produce solidification in the cold-box heat exchanger, the J-T valve or the distillation tower. It
Appendix E
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Technical and Economic Assessment of Potential to
Upgrade Gob Gas to Pipeline Quality
would not be possible to process a gas stream containing 3.3 percent oxygen in the amine unit.
This means that the deoxygenation unit must precede the amine unit, which in turn precedes
the distillation tower.
Inlet oxygen concentration to the catalytic deoxygenation unit is limited to 1.5 percent in order to
avoid high temperatures in the deoxygenation unit. In order to maintain the feed oxygen
concentration at or below 1.5 percent, a recycle scheme was developed. In the integrated
cryogenic process, the inlet flow rate to the deoxygenation unit is almost 3.5 times the feed flow
rate. This means that a facility processing 3 mmscfd of feed gas with the specified composition
would require a deoxygenation unit capable of processing about 10 mmscfd.
It should be noted that the waste gas stream contains about 12 percent methane when the
methane concentration in the feed is 70 percent and about 30 percent methane when the
methane feed concentration is 85 percent. Thus, flammability will not be a concern at higher
inlet concentrations. It would also be possible to create an optimized, energy efficient process if
the waste gas stream is used as fuel. This observation is found true for the other two
processes as well.
The principle findings of evaluations of the integrated cryogenics process for gob gas
enrichment are as follows:
• Oxygen is not removed in the same proportion as nitrogen in the distillation process. As a
result, the deoxygenation unit must precede all other process operations.
• The gas recycle requirements would require processing over three times the feed gas in the
deoxygenation unit. This would make the deoxygenation step expensive compared to when
no recycle is required.
• The overall process appears technically feasible, but complicated. Apart from the four
main process units, the process requires a number of additional heat exchangers and
special process equipment.
The team performed a sensitivity study of the integrated cryogenics process. The following lists
the three additional cases examined:
Flow rate Feed methane concentration
3 mmscfd 85 percent
5 mmscfd 70 percent
5 mmscfd 85 percent
Tables 2, 3, and 4 summarize the material and enthalpy balances for these three additional
cases. Comparison of the two cases (70 percent composition and 85 percent composition) at a
given flow rate provide an insight as to the level of control required when there are
compositional variations in the feed. It is observed that there are significant variations in duties
of heat exchangers, distillation column parameters, etc. For example, the condenser duty for
the distillation column changes by about 44 percent when methane concentration changes from
70 percent to 85 percent in the feed. The heat exchanger duties change by about 10-15
Appendix E
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Technical and Economic Assessment of Potential to
Upgrade Gob Gas to Pipeline Quality
percent for this compositional variation and by about 70 percent for feed flow rate change (3
mmscfd to 5 mmscfd). Thus, controlling the process with compositional and flow rate variations
will be complicated. Process designers may have a few options to mitigate the effect of these
variations if they are severe. These include: over-engineering various components; storing feed
gas and releasing it at a steadier rate; and recycling processed gas.
Lean-oil or Selective Absorption Process
Published GRI documents (GRI, 1991; GRI 1994) and information published by Advanced
Extraction Technologies (Mehra et al., 1993) formed the basis for the conceptualization of the
process. The process flow sheet is shown in Figure 3. Table 5 presents the material and
enthalpy balances for the base case study (3 mmscfd, 70 percent methane). The process flow
diagram was constructed using CHEMCAD. The simulations used generic solvents at
conditions most suitable for achieving the desired separation (determined by trial and error).
The process front-end, for the removal of oxygen would be identical to the cryogenics process.
The greatest advantage of the process is that it is flexible. It is also possible to obtain high-
purity product gas. Design parameters such as solvent to gas ratio and absorption column
recycle permit good control of the product gas quality even when feed flow and compositions
are varied. In addition, AET demonstrated the effectiveness of this technology (Mehra et al.,
1993) in removing nitrogen from methane. AET may also use proprietary solvents and
optimized conditions (based on their experience) to achieve better overall performance. The
integrated process does require a deoxygenation unit as large as the one for the combined
cryogenics method. The question of methane flammability does not arise since oxygen is
removed first.
Tables 6,7, and 8 present the material and enthalpy balances for three other cases (3 mmscfd,
85 percent methane; 5 mmscfd, 70 percent methane; and 5 mmscfd, 85 percent methane).
AET demonstrated good control in their gas treatment plant in Hugoton, Kansas when enriching
nitrogen contaminated natural gas. This demonstration plant has the capacity to process 5
mmscfd gas containing 13-19 percent nitrogen in the feed.
Principle findings of the evaluation of the selective adsorption approach to gas enrichment were
as follows:
• It is possible to achieve a high-purity product using the lean-oil or the selective absorption
approach.
• The NRU process is extremely flexible and will be able to accommodate compositional and
flow variations in the feed. Adjusting other units to meet these changes may be more
complicated, but is feasible.
• Since deoxygenation precedes all other process steps, a large deoxygenation unit will be
required for high oxygen concentrations.
Appendix E
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Technical and Economic Assessment of Potential to
Upgrade Gob Gas to Pipeline Quality
Pressure Swing Adsorption Process (PSA)
Separation of species using PSA may be governed by equilibrium or kinetic considerations.
Most equilibrium-based PSA processes use wide-pore molecular sieves while narrow-pore
molecular sieves (mostly zeolites) have been used for kinetic PSA separations. Most of the
work for the rejection of nitrogen from methane is reported using wide-pore carbon molecular
sieves, even though narrow pore zeolites have also been used to achieve the necessary
•separation. All of the technical evaluations in the current study were conducted for PSA
processes using wide-pore molecular sieves.
Pressure swing adsorption is a dynamic process. The operation of the process depends on the
breakthrough times of various gaseous components flowing through adsorption columns
pressurized on a cyclic basis. It is not possible to simulate dynamic processes using
conventional (steady-state) chemical engineering process simulators such as CHEMCAD. It
would be possible to simulate the process using special features of ASPEN PLUS (SPEEDUP),
an advanced process flow simulator. However, this exercise will require more time and is
beyond the scope of the current investigation.
The cyclic PSA operation shown in Figure 4 is a five-step process consisting of pressurization,
feed introduction, recycle, blowdown and purge. The following is a list of assumptions used in
performing the steady-state mass balance calculations (Ruthven, et al., 1994):
• Local equilibrium between the gas and the solid phase.
• Linear, uncoupled adsorption isotherms.
• Negligible axial pressure gradients.
• Constant pressure during feed and purge steps.
• Isothermal operation.
• Single component treatment of the oxygen-nitrogen pair.
The last assumption was based on the adsorption isotherm data for carbon dioxide, methane,
oxygen and nitrogen on wide-pore carbon molecular sieves at 303 K (Rodrigues, et al., 1989).
The adsorption isotherms, shown in Figure 5, indicate that carbon dioxide is the most strongly
adsorbed, followed by methane and that oxygen and nitrogen are only weakly adsorbed. The
isotherm curves for nitrogen and oxygen fall almost on top of one another. These isotherm
characteristics ensure that the separation efficiency of nitrogen and oxygen is almost identical
for PSA processes employing wide-pore carbon molecular sieves.
Equations governing the material balances for each of the steps are shown in Table 9 (Ruthven
et al., 1994). The table also explains the terms in these equations. The equations have been
derived for a simple two-component mixture and are for two-bed operation. The recovery
factors are functions of b, which in turn is a function of K|, the Henry's Law constant for each
constituent. KI'S are obtained using the adsorption data presented in Figure 5. The recovery
factors are also functions of the absolute pressure ratio, which is the ratio of the highest
pressure to the lowest pressure in the PSA cycle. The absolute pressure ratios for three feed
compositions were calculated for the binary methane-nitrogen mixture. The calculations are
tabulated in Table 10 and the recoveries are plotted in Figure 6. Table 10 and Figure 6 show
that for an ideal PSA process, it is possible to achieve high recoveries using different pressure
Appendix E
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Technical and Economic Assessment of Potential to
Upgrade Gob Gas to Pipeline Quality
ratios. The pressure ratio increases from 37 to 43 as the methane concentration in the gas
were to fluctuate from 92 percent to 72 percent. It should be noted that the recovery
calculations are for a two-component mixture undergoing PSA separation in a two-bed system.
When nonidealities and multiple components are considered, the PSA recoveries may not be
as high as shown in Figure 6. However, for lack of better data, the recoveries calculated using
the above described approach were incorporated in constructing integrated PSA flow charts.
Figure 7 presents the integrated PSA flow sheet. Table 11 shows the base case material and
enthalpy balances. Since oxygen is rejected along with nitrogen in PSA, it is only logical to
place the nitrogen rejection unit first. The PSA-NRU outlet stream contains only 0.72 percent
oxygen which is removed in the deoxygenator without the necessity of recycle. It should be
noted that for the base case (70 percent methane), the PSA reject stream contains about 17
percent methane. With higher methane recoveries (95 percent), the waste gas methane
concentration will dip below 15 percent, the upper flammability limit for methane. Hence, for
PSA processes designed for high methane recoveries, gas flammability will be a concern and
will have to be addressed appropriately. For better quality feeds (> 80 percent methane),
methane flammability will not be of concern. The integrated process is moderately complex
with a series of heat exchangers and compressors coupled to the main process units.
Material and energy balance tables for the other three cases are shown in Tables 12, 13 and
14. Since most of the oxygen removal is also accomplished within the PSA unit, control
required to account for compositional variations almost entirely rests in the PSA process. The
natural gas industry considers PSA to be a flexible process amenable to good and effective
control. This needs to be demonstrated, however, in the context of gob gas enrichment.
Principal findings for integrated gas clean-up using PSA include:
• For ideal, two-bed PSA operation, it is possible to achieve the desired separation between
methane and nitrogen. Non-ideal, multiple-bed processes could have recoveries far lower
than ideal.
• Nitrogen and oxygen are separated in the same proportion. Therefore, PSA-NRU units will
effect a significant level of deoxygenation, making the final oxygen removal step simpler.
However, when PSA units are designed for high methane recoveries (>95 percent),
methane flammability will be of concern and will have to be addressed.
• PSA is a flexible process. The pressure ratios and cycle times could be altered to meet
compositional and flow rate changes.
Appendix E
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Technical and Economic Assessment of Potential to
Upgrade Gob Gas to Pipeline Quality
Summary
1. The material and energy balances performed as part of this investigation have provided a
basis for assessing conversion technologies and for the evaluation of emerging processes
(such as fuel cells, bioreactors, etc.).
2. Controlling any of the three integrated processes is going to be a significant technical
challenge in the wake of feed compositional and flow rate variations. In order to maintain
strict specifications for the product gas, it may be necessary to mix the feed gas with a
higher-quality gas to keep the composition and feed within a permissible narrow range.
Because of these considerations, a pilot-scale demonstration of the integrated process is
advisable prior to field-scale implementation.
3. It may be possible to use the waste gas as fuel to create more energy efficient process
schemes (particularly, when feed gas quality is high).
4. In the cryogenics separation process, oxygen is not removed in the same proportion as
nitrogen. This makes recycle necessary for deoxygenation. Technical considerations
require the deoxygenation unit to precede all other process units. It is necessary to design
the deoxygenation unit to process 3.5 times more gas than the feed gas stream, when the
oxygen concentration in the inlet is about five percent.
5. The selective absorption process also requires deoxygenation as the first step. It is
possible to achieve high-purity product in the NRU-step of this process with considerable
flexibility.
6. PSA also offers a high degree of flexibility and under ideal conditions, the necessary
recovery during nitrogen rejection. Oxygen and nitrogen are separated together and makes
recycle (during deoxygenation) unnecessary for the PSA integrated approach until oxygen
concentrations exceed 10 percent.
7. If PSA processes are designed for high methane recoveries (>95 percent), when methane
feed gas concentrations are low (<70 percent), flammable mixtures will exist within the PSA-
NRU units. This concern will have to be appropriately addressed when considering high-
recovery PSA units.
Appendix E
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Technical and Economic Assessment of Potential to
Upgrade Gob Gas to Pipeline Quality
REFERENCES
GRI, 1990: Document GRI-90/020, Comparison of the Mehra Process for Nitrogen Rejection to
a Cryogenic Process for Nitrogen Rejection from Subquality Natural Gas.
GRI, 1991: Document GRI-91/0092, Evaluation of Process Costs for Small-scale Nitrogen
Removal from Natural Gas.
GRI, 1994: Document GRI-93/0448, Field Test Performance Evaluation of the Mehra Process
for Nitrogen Rejection from Natural gas.
Mehra, et al., 1993: Non Cryogenic N2 Rejection Process Gets Hugoton Field Test, Oil and Gas
Journal, May 24.
Rodrigues, A. E. et al. (Eds), 1989: Adsorption, Science and Technology, Kluwer Academic
Publishers, 269-283.
Ruthven, D. M. et al., 1994: Pressure Swing Adsorption, VCH Publishers, Inc., 95-164.
Appendix E
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Technical and Economic Assessment of Potential to
Upgrade Gob Gas to Pipeline Quality
APPENDIX F -
INFORMATION ABOUT THE
EPA COALBED METHANE OUTREACH PROGRAM
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FOR MORE INFORMATION...
For more information on coalbed methane recovery experiences, project potential, a full
listing of reports, or program activities and accomplishments, contact:
Coalbed Methane Program Manager
U.S. Environmental Protection Agency
Atmospheric Pollution Prevention Division
401 M Street, SW (6202-J)
Washington, DC 20460
Program Hotline: 1-888-STAR-YES
Facsimile: 202 565-2077
Internet: fernandez.roger@epamail.epa.gov
schultz.karl@epamail.epa.gov
Homepage: http://www.epa.gov/outreach/
Selected list of EPA Coalbed Methane Outreach Reports:
• USEPA (U.S. Environmental Protection Agency). To Be Released: Identifying
Opportunities for Methane Recovery at U.S. Coal Mines: Draft Profiles of
Selected Gassy Underground Coal Mines. Office of Air and Radiation (6202J).
Washington, D.C. EPA-430-R-94-012. December 1997.
• USEPA. Proceedings: Finance Opportunities for Coalbed Methane Projects.
Pittsburgh Airport Marriott Hotel, Pennsylvania, April 16-17,1996. Office of Air and
Radiation (6202J). Washington, D.C. EPA-430-R-96-013.
• USEPA. Finance Opportunities for Coal Mine Methane Projects: A Guide to
Federal Assistance. Public Review Draft. Office of Air and Radiation (6202J).
Washington D.C. EPA430-R-95-014. March 1996.
• USEPA. Finance Opportunities for Coal Mine Methane Projects: A Guide for
West Virginia. Public Review Draft. Office of Air and Radiation (6202J).
Washington, D.C. EPA-430-R-95-013. October 1995.
• USEPA. Finance Opportunities for Coal Mine Methane Projects: A Guide for
Southwestern Pennsylvania. Public Review Draft. Office of Air and Radiation
(6202J). Washington, D.C. EPA-430-R-95-008. June 1995.
• USEPA. Economic Assessment of the Potential for Profitable Use of Coal
Mine Methane: Case Studies of Three Hypothetical U.S. Mines. Public Review
Draft. Office of Air and Radiation (6202J). Washington, D.C. EPA-430-R-95-006.
May 1995.
Appendix F
-------
FOR MORE IN FORMATION, continued.
• USEPA. The Environmental and Economic Benefits of Coalbed Methane
Development in the Appalachian Region. Office of Air and Radiation (6202J).
Washington, D.C. EPA-430-R-94-007. April 1994.
• USEPA. Opportunities to Reduce Anthropogenic Methane Emissions in the
United States. Report to Congress. Office of Air and Radiation (6202J).
Washington, D.C. EPA-430-R-93-012. October 1993.
• USEPA. Anthropogenic Methane Emissions in the United States: Estimates
for 1990. Report to Congress. Office of Air and Radiation (6202J). Washington,
D.C. EPA-430-R-93-003. April 1993.
Appendix F
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UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
OFFICE OF
AIR AND RADIATION
Dear Colleague:
I am pleased provide you with a copy of the U.S. Environmental Protection Agency's most recent Coalbed
Methane Outreach Program's report, Technical and Economic Assessment of Potential to Upgrade Gob
Gas to Pipeline Quality. This assessment, prepared with the invaluable assistance of many experts from
universities, research institutes, and industry, contains perhaps the most up-to-date and comprehensive
treatment of commercially available technologies to process gob gas to meet pipeline company
specifications. The report covers the following pertinent topics:
Technical Evaluation of Cryogenics, Pressure Swing Adsorption, and Selective Absorption
Nitrogen Rejection Processes - Other Processes - Emerging Technologies - Cost Analysis of
Different Plant Sizes - Commercial Opportunities for Employing Gob Gas Processing - Effects of
Natural Gas Prices on Profitability - Market Incentives - a Stand-Alone Report by the University
of Utah; "Technical Evaluations of Enrichment Processes"- Information about the Coalbed
Methane Outreach Program - Contact Information for System Vendors and Experts.
The assessment's objective is to provide the coal industry and coalbed methane developers with
unbiased information on processing options, so that industry can determine if a system is worth exploring
further with vendors and developers.
EPA is committed to preparing technical and economic analyses that provide industry with real value-
added. Our aim is to empower decision makers with the best available information, so that they can
identify and develop coal mine methane projects that bring both profits and help to protect the
environment. Please call me at (202) 564-9468 or e-mail me at schultz.karl@epamail.epa.gov with
questions or comments.
Sincerely,
Karl Schultz
Manager, Coalbed Methane Programs
U.S. Environmental Protection Agency
enclosures
Recycled/Recyclable . Printed with Vegetable Oil Based Inks on 100% Recycled Paper (20% Postconsumer)
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Users guide to Upgrade Model
The analyst may use the Coalbed Methane Upgrade Model to establish cost-optimized
technical parameters for upgrading coalbed methane to pipeline quality natural gas. The
model assumes that the upgrade process includes some combination of recovery
improvement, enrichment, mixing (blending with high quality methane), and spiking. The
model refers to recovery improvement as "monitoring" which is just one of several
options available to the mine operator to maintain the highest possible methane content
of the recovered gob gas.
The following instructions provide the analyst with the tools needed to enter data,
perform the evaluation, and view the results.
1) The model consists of one file named "CMOP-Gasllpgrade.xls."
2) To enter the file, locate the file, highlight it, and double click.
3) The analyst will see the "Control" workbook, which provides the analyst with the
following menu:
Welcome
Input Resource & Output Specification
Evaluate
Display Results
4) The Welcome button displays a disclaimer message from the model's developer,
the University of Utah.
5) The Input Resource & Output Specification button displays the "Resource"
workbook, which is the data input menu for the model. The analyst will need to
enter flow information, input and output concentrations, cost information, and
computation options. Table 1 lists the inputs for the model.
Table 1
Inputs for Coalbed Methane Gas Upgrade Model
Input
Flow Information
Low Quality Gas
Methane in Gob Gas
Methane in Gob Gas
after Monitoring
Methane in Output
Gas
Oxygen
Concentration in Gob
gas
Blending Gas Price
Cell
Location
B8
B12
B15
B17
B20
B23
B28
Units
mmscfd
%
%
%
%
%
$/mmBtu
Comments
Total flow rate of both low and high quality gas
emitted from the mine - includes methane plus
contaminants, if any
Percentage of low quality gas in total flow (B8)
Percentage of methane in low quality gas, before
monitoring
Percentage of methane in gob gas after monitoring
Desired percentage of methane in output gas, Btu
equivalent
Percentage of oxygen in gob gas
Value of high quality gas from high quality CBM
-------
Input
Commercial Gas
Price
Propane Gas Price
Perform
Optimization?
Specify Discrete
Nodes?
Enrichment Output
Spiking Input
Cell
Location
B30
B32
B36
B39
B41
B42
Units
$/mmBtu
$/mmBtu
%
%
Comments
wells, if any
Value of pipeline gas if needed for blending
Cost of propane
Analyst may enter "O" or leave Cell B36 blank
If yes, the analyst enters "D" in Cell B39
If the analyst enters "D" in Cell B39, he/she must
enter the node point for enrichment output in Cell
B41
If the analyst enters "D" in Cell B39, he/she must
enter the node point for spiking input in Cell B42
6) The analyst completes the input table and presses the finish button, which
returns the analyst to the "Control" workbook.
7) Press the Evaluation button. The evaluation may take several minutes
depending upon the speed of the computer's processors. The computer
completes the evaluation and displays a message to notify the analyst.
8) Press the Display Results button to view the output. The output displays the
input parameters, followed by a table of results. The output provides results for
seven possible process combinations and cost estimates:
Table 2
Review of Output Coalbed Methane Gas Upgrade Model
Process Configuration Options
Enrichment Only - Low-End
Enrichment Only - High-End
Enrichment and Mixing with Methane
Enrichment and Spiking with Propane
Optimized Enrich, Mix, and Spike
Enrich, Mix, and Spike with User Selected
Discrete Nodes
Mix prior to Enrichment
Row
Number
17
18
20
29
38
47
57
Description
Low-end enrichment cost, assuming process uses no other
upgrade option to achieve pipeline quality.
High-end enrichment cost, assuming process uses no other
upgrade option to achieve pipeline quality.
Low-cost enrichment followed by blending with on-site and off-
site methane to reach the desired Btu level.
Low-cost enrichment followed by spiking with propane to reach
the desired Btu level.
Model optimizes enrichment, blending, and spiking sequence.
Enrichment followed by blending with methane and spiking
with propane at preselected nodes.
When blending prior to enriching is an option, the best choice
is mixing all available gas up to 6 mmscfd and enriching the
-------
Process Configuration Options
Mix, Enrich, and Spike
Row
Number
66
Description
mixture.
Another option is to mix, enrich and spike. These results are
an optimization of that option.
9) After viewing the output, the analyst may print the results using Excel print
commands or return to the "Control" workbook by striking the Finish button.
10) The analyst may wish to record several analyses to create follow-on analyses or
merely for convenient record-keeping. The analyst may copy the results on an
added Excel worksheet and record run parameters and results.
For questions concerning the model or the Technical and Economic Assessment of
Potential to Upgrade Gob Gas to Pipeline Quality report, please call Karl Schultz at 202
564-9468.
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