svEPA
United States
Environmental
Protection Agency
Air and Radiation
(6202 J)
EPA-430-R-98-019
October 1998
Technical and Economic
Assessment of Coalbed
Methane Storage in
Abandoned Mine Workings
\ETHAN
OUTREACH
> R O C R A M
-------
-------
C O A
METHANE
OUTREACH
PROGRAM
Technical and Economic Assessment of
Coalbed Methane Storage in Abandoned
Mine Workings
Coalbed Methane Outreach Program
Atmospheric Pollution Prevention Division
U.S. Environmental Protection Agency
October 1998
-------
ACKNOWLEDGMENTS
This report was prepared under Work Assignment 3-2 of U.S. Environmental Protection
Agency (U.S. EPA) Contract 68-W5-0017 by Alternative Energy Development, Inc. and
Resource Enterprises. EPA also recognizes the contributions of LAND Energy, Inc. and
CONSOL, Inc., who provided peer reviewers for the final draft of this document.
-------
CONTENTS
FIGURES Ill
TABLES IV
MEASURES AND ACRONYMS V
1 INTRODUCTION 1
1.1 BACKGROUND 1
1.2 DOMESTIC GAS SUPPLY, DEMAND TRENDS, AND PRICING 1
1.3 POTENTIAL ADVANTAGES OF LOCAL GAS STORAGE FOR COALBED METHANE PROJECTS 3
1.3.1 Supply Stream Dampening 3
1.3.2 Support Peaking Demands 4
1.4 COAL MINE GAS STORAGE EXPERIENCE 4
1.4.1 Gas Storage in Belgian Coal Mines 4
1.4.2 Gas Storage in an Abandoned Lignite Mine near Denver, Colorado 5
2.0 STORAGE OF GAS IN ABANDONED COAL MINES 7
2.1 TECHNICAL, SAFETY, AND ECONOMIC CONSIDERATIONS 7
2.1.1 Storage in Abandoned Mines 7
2.1.1.1 Using Abandoned Coal Mines for Gas Storage 7
2.1.1.2 Methane Sorption and the Storage Potential of Abandoned Coal Mines 8
2.1.1.3 Technical Issues Relating to Abandoned Mine Gas Storage 10
2.1.2 Storage in Sealed Areas of Active Mines 13
2.1.2.1 Sealing of Worked Areas 14
2.1.2.2 Leakage Dynamics Between Sealed Areas and Mine Airways 14
2.1.2.3 Example 15
2.1.2.4 Sealed Area Pressurization 18
2.2 POTENTIAL FOR ABANDONED MINE GAS STORAGE NEAR THE 21 GASSIEST U.S. MINES 20
2.3 OWNERSHIP OF CONTAINER SPACE FOR STORAGE IN ABANDONED MINES 22
2.3.1 Ownership Issues 22
2.3.2 Coalbed Methane Ownership Arguments 22
2.3.3 Storage Container Ownership Claims and Court Holdings 23
2.3.3.1 Coal Owner 23
2.3.3.2 Surface Owner 23
3.0 CONCEPTUAL STORAGE FACILITY 25
3.1 CASE DEFINITION 25
3.1.1 The Abandoned Mines 25
3.1.2 Storage Capacity 25
3.1.3 Facility Performance Objectives 26
3.2 FACILITY CONFIGURATION 26
3.2.1 Shaft and Borehole Sealing 26
3.2.2 Wells 27
3.2.3 Compression 27
3.2.4 Gas Transport 28
3.2.5 Power 28
3.2.6 Water Storage and Disposal 28
-------
3.3 FACILITY OPERATIONS 28
3.3.1 Phase I - Design and Testing for Containment 28
3.3.2 Phase I! - Construction 29
3.3.3 Phase III - Operations 29
3.4 FACILITY COSTS 29
3.4.1 Capital Costs 29
3.4.2 Operating Costs 32
4.0 CONCEPTUAL STORAGE FACILITY USE AND ECONOMICS 33
4.1 MODE OF OPERATION 33
4.2 ECONOMIC ANALYSES 33
4.2.1 Technical Assumptions 34
4.2.2 Financial Assumptions 34
4.2.3 Results 35
4.3 SUMMARY OF ECONOMIC ANALYSES 42
5.0 CONCLUSIONS 43
5.1 GAS STORAGE IN ABANDONED COAL MINES 43
5.1.1 Technical Issues Relating to Storage 43
5.1.2 Experience in Abandoned Coal Mine Storage 44
5.1.3 Conceptual Facilities 44
5.1.4 Conceptual Facility Economics 44
5.2 GAS STORAGE IN SEALED AREAS OF ACTIVE MINES 45
5.3 RECOMMENDATIONS FOR FURTHER STUDY 46
6.0 REFERENCES 47
-------
FIGURES
Figure 1.1: Domestic Natural Gas Demand, Supply Source, and Spot Price 2
Figure 1.2: Average Monthly Natural Gas Spot Prices (Henry Hub) for 1994 through
June 1997 3
Figure 1.3: Natural Gas Spot Price Projections to Year 2000 Based on NYMEX Futures 3
Figure 2.1: Sorption Isotherm for Various Eastern U.S. Coals at 86 Degrees F and
Dry Ash and Moisture Free Basis 9
Figure 2.2: Shaft Seal Implemented at the Leyden Storage Facility 11
Figure 2.3: Adsorptive Capacity of a Coal for Two Inert Gases Relative to Methane 13
Figure 2.4: Standard Seal Construction as per CFR Title 30, Part 75.335 15
Figure 2.5: Sealed Area Pressure Variation with Changes in Atmospheric Pressure
Outby fora Number of Seals in Parallel 16
Figure 2.6: Cumulative Leakage from Sealed Area with Changes in Atmospheric
Pressure Outby fora Number of Seals in Parallel 17
Figure 2.7: Ventilation Requirements to Dilute Emissions from Seals to less than
2 Percent by Volume during Atmospheric Pressure Changes 17
Figure 2.8: Methane Leakage through Seals during Injection Period and at Steady State 19
Figure 2.9: Ventilation Airflow Required to Dilute Methane Emissions from Seals
during Injection Period and at Steady State 19
Figure 3.1: Conceptual Storage Facility General Layout 27
Figure 4.1: IRR for Conceptual Storage Facility A as a Function of Mean Annual
Gas Sales Price and Number of Maximum Withdrawal Days Per Year 38
Figure 4.2: Pay-Back Period for Conceptual Storage Facility A as a Function of
Mean Annual Gas Sales Price and Number of Maximum Withdrawal
Days Per Year 39
Figure 4.3: NPV for Conceptual Storage Facility A as a Function of Mean Annual
Gas Sales Price and Number of Maximum Withdrawal Days per Year 39
Figure 4.4: IRR for Conceptual Storage Facility B as a Function of Mean Annual
Gas Sales Price and Number of Maximum Withdrawal Days Per Year 40
Figure 4.5: Pay-Back Period for Conceptual Storage Facility B as a Function of
Mean Annual Gas Sales Price and Number of Maximum Withdrawal
Days Per Year 41
Figure 4.6: NPV for Conceptual Storage Facility B as a Function of Mean Annual
Gas Sales Price and Number of Maximum Withdrawal Days per Year 41
Figure 5.1: IRR for the Conceptual Storage Facility (A) as a Function of Gas Sales
Price and Number of Maximum Withdrawal Days per Year 45
-------
TABLES
Table 2.1: Location of Top 22 Gassy Mines in the U.S. by State and County 20
Table 2.2: Recorded Number of Identified Abandoned Coal Mines Since 1959 by County 21
Table 3.1: Conceptual Storage Facility Characteristics 26
Table 3.2: Facility Performance Characteristics 26
Table 3.3: Total Costs Estimated for Phase I Design and Containment Testing
for Facility A 30
Table 3.4: Estimated Detailed Design and Construction Costs for Facility A 30
Table 3.5: Total Costs Estimated for Phase I Design and Containment Testing
for Facility B 31
Table 3.6: Estimated Detailed Design and Construction Costs for For Facility B 31
Table 3.7: Monthly Operating Expenses for the Proposed Storage Facility A 32
Table 3.8: Monthly Operating Expenses for the Proposed Storage Facility B 32
Table 4.1: Scenarios Evaluated by Analyses for Both Facilities A and B 35
Table 4.2: Facility A, Cash Flow Statement for the 35 Maximum Withdrawal Days and
$3.50 per mscf ($123.60 per 1000 sm3) Average Peak Gas Sales Price 36
Table 4.3: Facility B, Cash Flow Statement for the 35 Maximum Withdrawal Days and
$3.50 per mscf ($123.60 per 1000 sm3) Average Peak Gas Sales Price 37
IV
-------
MEASURES AND ACRONYMS
Measures:
bcf
bhp
bscf
Btu
cf
cfm
Hg
hp
kcfm
kPa
kV
kW
m3/t
mcfd
MJ/sm3
mmBtu
mmcf
mmcfd
mmscf
mmscfd
MPa
mscf
Msm^d
psi
psia
psig
P.U.
scf
sm3
tcf
w.g.
Billion cubic feet
Brake horsepower
Billion cubic meters
Billion standard cubic feet
British thermal units
Cubic feet
Cubic feet per minute
Mercury
Horsepower
Thousand cubic feet per minute, air ventilation
Kilo Pascal
Kilovolt
Kilowatt
Cubic meters
Cubic meters per second
Cubic meters per tonne
Thousand cubic feet per day
Mega Joule per standard cubic meters
Million cubic meters
Million British thermal units
Million cubic feet
Million cubic feet per day
Million standard cubic feet
Million standard cubic feet per day
Million Pascal
Thousand standard cubic feet
Million standard cubic meters
Million standard cubic meters per day
Resistance to airflow
Pounds per square inch
Pounds per square inch, absolute
Pounds per square inch, gauge
Practical unit of resistance to airflow (milli inches w.g. / mcfm2)
Standard cubic feet
Standard cubic meters
Trillion cubic feet
Pressure in water gauge (inches of water)
Acronyms:
CFR Code of Federal Regulations
U.S. DOI U.S. Department of the Interior
U.S. EPA U.S. Environmental Protection Agency
FERC Federal Energy Regulatory Commission
IRR Internal Rate of Return
LDC Local Distribution Companies
MSHA U.S. Mine Safety and Health Administration
NPV Net Present Value
NYMEX New York Mercantile Exchange
V
-------
VI
-------
Technical and Economic Assessment of Coalbed Methane Storage in Abandoned
Mine Workings
1 INTRODUCTION
1.1 BACKGROUND
Most commercial coal mine methane (CMM) projects in the United States recover high-quality
coalbed methane for sale to natural gas pipelines. Furthermore, most projects blend gas
recovered from vertical wells and horizontal inseam boreholes developed in virgin coal seams in
advance of mining with high-quality gas recovered from gob wells. Typically, therefore,
commercial CMM projects rely on and are constrained by mining activities that invariably affect
gas production rates, and, where gob gas is recovered, the quality of the gas.
There is a growing awareness among CMM operators that nearby field storage can help facilitate
projects that use pipeline-quality or gob gas. Storage facilities with high deliverability (the ability to
inject and withdraw gas at high volumes) could assist in normalizing gas production and allow
projects to take advantage of high market demand and pricing periods (e.g., peak-load facilities).
Many active gassy mines are located near closed mines or mines that will close because they are
depleted or uneconomical. These underground voids may have good gas storing potential.
This report presents an introductory section illustrating annual natural gas market trends in the
United States, the potential advantages to CMM projects of local gas storage, and the current
level of experience with gas storage in abandoned mines. Subsequent sections discuss technical
issues relating to gas storage in abandoned mines, including the availability of abandoned mines
near current commercial CMM projects, and present a conceptual storage facility design for a
hypothetical CMM pipeline injection project. The final section discusses the results of economic
analyses conducted for the conceptual facility.
1.2 DOMESTIC GAS SUPPLY, DEMAND TRENDS, AND PRICING
United States natural gas demands fluctuate seasonally since natural gas is a main source of
heating fuel. Figure 1.1 illustrates the seasonal fluctuation in domestic natural gas demand,
source of gas, and average natural gas spot price (based on the spot price at the Henry Hub in
Louisiana) for the year 1996. The combination of (1) this demand fluctuation, (2) recognition of
the environmental benefits of natural gas, and (3) the associated impacts on the natural gas
delivery system (e.g., the high cost of constructing pipeline capacity, including impacts of FERC
Order 636 - unbundling of pipeline and storage services) spurred increased construction of
underground gas storage facilities in the United States (Beckman and Determeyer, 1997).
Specifically, facilities constructed were capable of high deliverability with flexibility in injection and
withdrawal cycles (e.g., peak-load facilities). Presently there are over 400 natural gas storage
facilities operating in the United States with total deliverability in excess of 3.5 tcf (100 bm3) (total
domestic working gas in storage). Currently, daily storage supply capability is approximately 70
bcf (2 bm3) (American Gas Storage Survey, 1997). Present domestic peak demand during severe
winter conditions is greater than 80 bcf (2.3 bm3) per day. Imported gas makes up some of the
difference during peak periods, as shown on Figure 1.1.
Storage facilities strive to counter the imbalance between seasonal supply and demand. Storage
companies (now mostly owned by local distribution companies - LDCs) purchase gas during off-
peak periods, particularly in summer months when natural gas demands are low and supplies are
high, and withdraw gas during peak demand periods, typically in the winter. Anticipated increases
in demand, primarily those associated with inclement weather conditions, are critical to market
stability during winter months. Unseasonable climatic conditions that lead to early storage gas
-------
withdrawal and mismanagement of storage resources can send natural gas prices soaring.
Figures 1.1 (for 1996) and 1.2 illustrate how seasonal domestic natural gas spot prices (average
monthly) fluctuated from 1994 through the first half of 1997 (Henry Hub, Louisiana). Although the
industry has more efficient, flexible, high-deliverability storage facilities under construction and
uses new storage management techniques, annual imbalances between supply and demand,
resulting in spot gas price swings, will likely continue. Figure 1.3 illustrates projected futures for
natural gas to the year 2000 at Henry Hub, Louisiana (where the NYMEX futures contract is
traded).
Looking at average monthly spot price trends during the last three years (Figure 1.2), the largest
seasonal price difference transpired between September 1996 and January of 1997; a $2.25 per
mmBtu difference ($79.46 per 1000 sm3 assuming 1000 Btu per standard cubic foot gas). Using
the NYMEX Futures (Figure 1.3), seasonal variations of at least $0.40 per mmBtu ($14.13 per
1000 sm3) are expected to the year 2000.
3,000
Imports
C3 Storage
^3 Production
-^Henry Hub Spot Price
Months, 1996
Figure 1.1: Domestic Natural Gas Demand, Supply Source, and Spot Price (Henry Hub, Louisiana)
for 1996 (ElA, 1996)
-------
Months 1994 through 1997
Figure 1.2: Average Monthly Natural Gas Spot Prices (Henry Hub) for 1994 through June 1997
(El A, 1994-1997)
$2.60
$2.50
$2.40
m
I $2.30
i
V*
$2.20
$2.10
$2.00
Months July 1997 to Year 2000
Figure 1.3: Natural Gas Spot Price Projections to Year 2000 Based on NYMEX Futures (Wall Street
Journal, 1997)
1.3 POTENTIAL ADVANTAGES OF LOCAL GAS STORAGE FOR COALBED METHANE PROJECTS
The availability of high deliverability gas storage near CMM projects could enhance coalbed
methane recovery and use. This capability could dampen feed stream supply fluctuations and
provide operators with the ability to sell into natural gas demand peaks.
1.3.1 Supply Stream Dampening
Degasification system gas production varies with the rate of coal production. Thus, designs for
coalbed methane processing and use facilities, including those for commercial pipeline injection,
-------
power generation, and self-use projects, must accommodate fluctuating gas supply. For example,
changes in mine plans, mining activity (changes in advance rate, etc.), degasification drilling
activities, and the gas collection system affect system gas production. Ideally, processing and
use facilities for coalbed methane projects consist of modules (smaller scale, multiple component
systems) to ensure some plant operability during low feed supply and some added capacity during
supply surges. To accommodate low-supply periods, gas processing systems sometimes use
gas recirculation capabilities to enable operation. In all cases, operators design coalbed methane
processing and use facilities to operate at an optimum fuel feed rate and to peform efficiently
within designed tolerances. Exceeding tolerances can cause system inefficiency, and, in some
cases, can cause operations to cease.
Available gas storage would stabilize supply feed streams, allow for consistent product
deliverability, and increase project availability. During high CMM production periods, operators
can inject excess supply gas into storage. They can then withdraw the gas during lower
production periods to dampen variations in feed stream production. High deliverability storage will
accommodate short surges in production by injecting and rejecting high volumes of gas over short
periods of time. Generally, storage provisions would allow for more consistent product
deliverability.
1.3.2 Support Peaking Demands
Use of storage for peak shaving (supplying from storage to market during peak demand periods)
could significantly benefit CMM projects, particularly if a high deliverability facility is available.
High deliverability storage capability could enable a CMM pipeline injection project, for example, to
sell more gas during peak gas demand periods when spot prices are higher. This can improve
the overall economic viability of some CMM projects.
1.4 COAL MINE GAS STORAGE EXPERIENCE
The natural gas industry generally does not consider abandoned coal mine workings for gas
storage because of sealing and storage capacity concerns. However, two such facilities,
developed from dewatered abandoned gassy coal mines, are presently in use in Belgium. An
abandoned sub-bituminous coal mine houses the only similar facility in the United States
(operated by the Public Service Company of Colorado). All of these projects were implemented
with 1960 - 1970 technology and know-how. This section presents an overview of these projects.
Details of the U.S. project are presented in the U.S. EPA White Paper entitled "Gas Storage at the
Abandoned Leyden Coal Mine near Denver, Colorado" (U.S. EPA, 1998a).
1.4.1 Gas Storage in Belgian Coal Mines
Distrigaz, a Belgian gas company, operates gas storage facilities at two abandoned mines in the
Campine coal fields in Belgium. These two facilities store in excess of 10 bcf (283 Mm3) of
imported natural gas for use during peak demand periods (Dusar and Verkaeren, 1991).
The two mines are the Peonnes and Anderlues mines, which ceased coal production in 1969.
Both were gassy and incorporated methane drainage systems. The mines continued to produce
gas after operators sealed the access shafts. Seals isolated more than 10 shafts in the Anderlues
mine and 19 in the Peonnes mine. Operators monitored gas emitted from observation wells
installed in several of the shafts until methane purged the mines of air. They then began to collect
-------
and sell the recovered gas into Distrigaz pipelines. Peak yearly gas production for each mine was
roughly 630 mmcf (18 Mm3) after sealing.
As a result of extensive mining in the region, the Peonnes and Anderlues mines were relatively
dry and necessitated little dewatering while in production. Mine operators extracted coal from
multiple levels of both mines, initiating at near 320 ft (98 m) below the surface and extending to
3,600 ft (1100m). For gas storage, the maximum operating pressure is no greater than 40 psi
(276 kPa) gauge because of the shallow workings. Main Distrigaz pipelines expand and inject
gas into the abandoned mines near this pressure. According to an internal Distrigaz report, gas
adsorption effects associated with the remaining coal enhance storage facility capacity at the
Peonnes and Anderlues mines over tenfold (U.S. EPA, 1998a). Preferential sorption of higher
hydrocarbons contained in the injected gas by the remaining coal in these facilities requires
Distrigaz operators to enrich withdrawn gas with propane. Operators also need to dehydrate the
gas prior to reinjection into Distrigaz pipelines.
1.4.2 Gas Storage in an Abandoned Lignite Mine near Denver, Colorado
To provide peaking demands for the Denver, Colorado area, Public Service of Colorado
experimented with gas storage in a large abandoned water-filled sub-bituminous coal mine near
Leyden, Colorado in 1960. Initial evaluations involved an assessment of mining records,
exploratory coring, and eventual experimentation with air injection into a high point in the mine.
After pressure monitoring revealed no significant leakage, the company drilled additional wells and
eventually contained 750 mmcf (21.2 Mm3) of natural gas at 200 psig (1.4 MPa). Pressure
monitoring over a two-month shut-in period revealed relatively constant gas pressures and water
levels. After 18 months of testing and evaluation, the company decided to proceed with
development of the entire facility and proceeded to seal the four mine shafts. Critical for gas
containment, Public Service of Colorado elected to use a sealing design proposed by Fenix and
Scisson Inc. (Hooker, 1990). The design involves constructing a concrete abutment in the shafts
just below an impervious zone of strata. The abutment is keyed into the surrounding strata and
serves to contain a pressure cell developed in the shaft in the overlying impervious zone. This
effort required cleaning out the shafts, and filling them initially with concrete and gravel to the level
of the concrete abutment. Public Service of Colorado maintains an over-pressured condition in
the impervious zone in all shafts with a high-density mud supply system.
Sealing proved successful, so the company drilled 17 wells into the old mine workings: three for
dewatering and observation, and the rest for gas injection and withdrawal. After 1963, the facility
held in excess of 2 bcf (57 Mm3) of natural gas with deliverability rates of up to 140 mmcfd (4
Mm3). Over the years, the facility has been upgraded and can now deliver up to a maximum of
230 mmcfd for five consecutive maximum withdrawal days (initiating from peak storage pressure
of 250 psig (1.72 Mpa)). The facility presently stores approximately 3 bcf (85 Mm3) of gas and
has a maximum working capacity of 2.2 bcf (62.3 Mm3). The facility provides the Denver area
with up to 20 percent of its winter peaking demands (up to 1.1 bcf (28.3 Mm3)). Furthermore, it
enables Public Service of Colorado to balance its gas supplies by allowing it to purchase gas at
off-peak prices (i.e., to avoid purchasing gas during peak pricing periods).
During injection, gas from main pipelines expands as it enters the facility. It is necessary to scrub,
dehydrate, and odorize gas withdrawn from the facility before recompression for pipeline injection.
Public Service of Colorado uses the facility specifically for peak shaving, and therefore, withdraws
and injects gas frequently (about 300 days per year). The facility has cost Public Service of
Colorado approximately $18 million since 1960. Labor and well maintenance costs are
approximately $800,000 per year (U.S. EPA, 1998a). Public Service of Colorado estimates that
-------
the facility saves in excess of $14 million per year by avoiding purchasing gas at peak prices to
satisfy peak demands.
-------
2.0 STORAGE OF GAS IN ABANDONED COAL MINES
Storing coalbed methane in abandoned coal mines or sealed mine workings is of interest to CMM
developers and operators because such opportunities are available at gassy mines and at mines
where commercial CMM projects operate.
2.1 TECHNICAL, SAFETY, AND ECONOMIC CONSIDERATIONS
2.1.1 Storage in Abandoned Mines
In general, the natural gas industry has not moved toward using abandoned mines for storage
purposes for two reasons. First, there are gas containment concerns with these facilities.
Second, because mines, particularly coal mines, are generally shallow, storage pressures, and
hence storage capacities, are low'relative to those for conventional storage facilities, such as
depleted natural gas reservoirs and aquifers. In abandoned coal mines, however, gas adsorptive
effects may increase storage capacity and ease volume concerns. Although abandoned coal
mines may not be suitable for high-volume and high-pressure natural gas storage, they still may
benefit commercial CMM projects, particularly if they can improve the economics of these
projects.
2.1.1.1 Using Abandoned Coal Mines for Gas Storage
Coal mine gas storage experience in the U.S. and in Belgium demonstrates the feasibility of
storing gas in abandoned coal mines that are under two different conditions. In the first case, U.S.
operators identified a site where hydrological conditions provide a water seal to contain the gas.
In the second case, Distrigaz operators use a dry gassy mine in an extensively mined area and
rely only on the characteristics of the surrounding geology to isolate the gas. The following
discussions address general storage facility development and operating procedures for each
case:
Water Containment
For facilities that initially are all or mostly inundated with water, facility developers inject gas while
they remove water by pumping, and maintain gas pressures at a maximum of 65 to 70 percent of
the hydrostatic pressure at the mine level. Depending on hydrological conditions, the ground
water may maintain a seal around most of the gas space. During facility operations, water
removal continues to maintain facility volume, and gas delivery is driven by gas storage pressure.
In this case, coal cleats and natural fractures are initially water saturated, and, depending on
water removal, gas injection rates, and pressures, this may limit injected gas adsorption to
immediate coal surfaces as described in more detail below.
Geologic Containment
Significant adsorptive capacity may be available in dry abandoned gassy mines, or mines where
dewatering has been maintained, or in gassy mines suitable for gas storage that are about to
close. In the latter case, while the mine is being sealed, gas desorption may continue. Project
operators can use this process to purge air from the subsurface workings and then allow the mine
pressure to build up and stabilize. This shut-in pressure may serve as the minimum storage
pressure and the facility may have an inherent supply of cushion gas (see Section 2.1.1.3). The
mine may store gas under pressure, provided there is vertical and horizontal isolation. During gas
-------
injection under pressure, fractures and joints may provide conduits for methane to migrate to
larger coal reserves, enhancing gas adsorption and increasing the storage volume of the facility
(also increasing cushion gas requirements). Because of gas containment concerns, operators
typically use such facilities for very low pressure storage.
For storage of gas in abandoned mines, gas containment concerns are best resolved by establishing
facilities at mines where a water seal can contain the gas. Unfortunately, such conditions may
somewhat impair the ability of the mine's remnant coal to increase storage through adsorption as
discussed in greater detail below.
2.1.1.2 Methane Sorption and the Storage Potential of Abandoned Coal Mines
The potential to increase the storage capacity of abandoned coal mines beyond the volume of
available free space by re-adsorption of methane onto remnant coal is attracting the interest of
CMM operators who are considering the benefits of abandoned coal mine storage. Typically, 95
percent of the total gas contained in coal is in the adsorbed form (as opposed to free gas in coal
pore structures, microfractures, cleats, and natural fractures). In abandoned coal workings,
methane from coal pillars and exposed coal ribsides will have desorbed during mining, depending
on time, mining factors, cleat and natural fracture permeability, water saturation, desorption, and
other reservoir characteristics. Methane re-introduced into abandoned workings at pressure will
re-adsorb onto coal surfaces to the extent determined by the adsorption characteristics of the coal
(specifically methane storage capacity and diffusion time), the injection pressure, permeability,
and degree of water saturation.
Methane Storage Capacity of Coals
The ability of coal to adsorb methane depends on the coal carbon content, the partial pressure of
methane, gas temperature, and coal moisture content. For the range of pressures of interest to
this study, literature typically presents methane storage capacity as a function of gas pressure at
specified temperature and on a dry, ash-free basis as described by the Langmuir equation
(McPherson, 1993). Figure 2.1 presents results of published methane sorption isotherm tests
conducted for a range of gassy eastern U.S. coals (modified from Joubert et al.,1973, and Kim,
1977). Coals of higher fixed carbon content, and therefore rank, have higher methane storage
capacity.
From a gas storage perspective, abandoned mines that exploited coals such as anthracite or low-
to medium-volatile bituminous will have higher capacity for storage (see also cushion and
unrecoverable gas technical issues discussed below). In assessing an abandoned mine's
potential for gas storage, developers should determine the in-situ methane storage capacity of the
coals, accounting for moisture and ash content. Moisture and ash content decreases the storage
capacities from those indicated on Figure 2.1.
Diffusion Time
Diffusion flow controls the rate at which methane moves between the coal cleats and natural
fractures and the coal matrix (the micropore and microfracture surfaces). During storage facility
operations where gas pressures increase and decrease with gas cycling, the rate of diffusion
becomes an important parameter, particularly if coal gas storage capacities are high. The rate of
gas diffusion depends on the methane concentration gradient in the matrix and on the coefficient
of diffusion of the coal. In methane recovery, the coefficient of diffusion is calculated from the
sorption time determined from direct measurements of gas content (time for 63 percent of the
methane to desorb from a coal sample) and fracture spacings. Sorption time (used in the industry
as a qualitative indication of diffusion rate) for U.S. coals varies considerably, ranging from 2
-------
hours to 900 days. Of the eastern U.S. coals identified in Figure 2.1, studies indicate that the
diffusion rate for the Pocahontas No.3 seam is considerably faster (100 times) than that for the
Pittsburgh coal seam (Kissell and Bielicki, 1972).
0.00
200.00
600.00
Pressure (psi)
1200.00
Figure 2.1: Sorption Isotherm for Various Eastern U.S. Coals at 86 Degrees F and Dry Ash and
Moisture Free Basis (modified from Kim, 1977)
Note: 1 psi = 6.895 kPa, 100 ft3/ton = 3.12 m3/tonne
To take advantage of the large methane retention capability of coals and to inject and recover gas
quickly, abandoned mine storage facility designers should select mines that exploited coals with
high methane storage capacity and that exhibit fast diffusion rates. Coals that exhibit high
methane storage capacity but slow diffusion rates are likely not suitable for storage because
diffusion times may constrain deliverability and injection rates. The authors anticipate that,
because of the extent of exposed coal surfaces in an abandoned mine (pillars and ribsides),
diffusion in addition to permeability will play an important role in abandoned coal mine gas
storage, particularly with regard to injection and deliverability rates. In contrast, methane recovery
authorities typically assume that methane production is primarily permeability controlled and that
diffusion rates are negligible relative to the rate of methane transport through cleats and natural
fractures to the wellbore.
Permeability
The permeability of coal is determined by the aperture, continuity, and frequency of cleats and
natural fractures. This network serves as the conduit for methane to migrate into coal and enter
into the coal matrix through diffusion. Gas flow through this network follows Darcy's law for fluid
flow through porous media, which depends on the pressure gradient in the network, fluid
properties (viscosity), the permeability of the coal media (to gas and water), and the degree of
water saturation of the coal. The presence of water in the cleat and fracture network significantly
-------
reduces the permeability of the system to gas (e.g., the relative permeability of the system to gas
decreases with increasing water saturation).
With regard to storage of methane in abandoned mines, sites initially inundated with water will
contain coals with high water saturation levels. Depending on dewatering conditions (dewatering
time and gas injection pressures), storage operators may be unable to use all of the methane
retention potential of the remnant coal because of some remaining degree of water saturation.
2.1.1.3 Technical Issues Relating to Abandoned Mine Gas Storage
Abandoned mines that can provide a water seal to contain the gas and with minimal connections
to the surface and no connections to active workings are suitable for gas storage. Concerns
regarding gas storage in abandoned coal mines mostly relate to containing the gas within the
underground excavation, maximum operating pressures, the integrity of the workings during
pressure cycling, and the effects of preferential sorption on processing requirements for the
withdrawn gas.
Gas Containment Considerations
As stated by gas storage authorities, gas containment within storage facilities is the primary
concern of site operators (Tek, 1987). For abandoned coal mine storage, operators can achieve
reasonable gas containment by selecting sites where a water seal can contain the gas, and where
shafts and surface connections are minimal and suitable for sealing.
Facility Containment: Water seals coupled with impermeable strata provide the best means of
gas containment for abandoned coal mines. For example, competent, impermeable strata
overlying the mining horizon and an underlying water-bearing sandstone provide vertical
isolation for the Leyden Facility in Colorado. The water-bearing sandstone also provides
horizontal gas containment by inundating the surrounding mine workings and saturating the
overlying coal. Operators should consider site geologic and hydrological conditions when
assessing vertical sealing potential, and should evaluate how mining has affected these
conditions. Abandoned room and pillar workings with minimal secondary mining will have less
impact to overlying strata than longwall mining, for example.
Shaft Seals: Facility developers will need to construct proper seals in the abandoned mine's
shafts in order to contain gas. For sealing of access shafts in excavated facilities, the storage
industry adopts the pressure balance sealing technique (Nilsen and Olsen, 1989). The
technique maintains an over-pressured space in the shaft at an impermeable horizon between
two static abutments. Figure 2.2 illustrates this sealing technique employed at the Leyden
mine. The facility manager maintains the over-pressured condition in the cell by continuously
monitoring the high density injection fluid level in the monitoring pipe and by controlling the
fluid level. Prior to constructing pressure cells, Public Service of Colorado also initially cleared
the abandoned shafts of fill and plugging debris, dewatered the shafts, poured concrete
footings, and inserted fill material as illustrated in Figure 2.2. Facility developers should select
candidate sites with minimal surface connections to minimize costs of clearing existing shaft
plugs and constructing appropriate pressure-sustaining shaft seals.
Sealing Fissures and Joints: Joints and fissures connecting mine workings to charged
aquifers with high hydraulic conductivity are a serious concern. These connections may have
developed after mining, and would make it difficult for storage operators to extract the ground
water for displacement by injected gas. The facility developer should select sites where
mining has caused minimal disturbance to overlying strata and where mining records show no
experience of such conditions. In some cases, operators may attempt to seal large identified
10
-------
fissures that interface with the abandoned workings by the costly process of injecting grout
through intersecting boreholes drilled from the surface. The operator can then evaluate the
effectiveness of the grouting during the pumping and gas injection operations. Because the
degree of perviousness may not be easily ascertainable, the operator likely would need to
conduct this process by trial and error.
Providing an Artificial Water Seal: Storage field operators have used water curtains to
artificially provide vertical and horizontal isolation of storage volumes excavated in hard rocks
(Nilsen and Olsen, 1989). They typically develop a vertical well with multiple deviated
horizontal wells or tunnels above the storage area. The operator supplies this infrastructure
with water under pressure to generate a continuous pieziometric surface overlying the storage
area.
Figure 2.2: Shaft Seal Implemented at the Leyden Storage Facility (U.S. EPA, 1998a).
Operating Considerations
Maximum Operating Pressure: Gas pressures in abandoned coal mines contained by a water
seal cannot exceed the hydrostatic pressure at the mining level. The hydrostatic pressure at
the mining horizon is 0.43 psi per foot (9.73 kPa per m) below the surface level. Generally,
maximum operating pressures for gas storage should not exceed 65 to 70 percent of this
value. Because coal mines are normally shallow, hydrostatic pressures are low, and storage
operating pressures (thus storage volumes) are therefore low. A mine at 800 feet (245 m)
below the surface, for example, could potentially operate as a storage facility at a maximum
pressure of approximately 240 psi (1.65 MPa) gauge pressure. This would result in a net
storage volume of approximately 16 times the volume of the available space (not counting
additional capacity provided by adsorption capability of the exposed coal to gas). This is a
11
-------
relatively small ratio from a natural gas industry perspective (for example, salt caverns can
store gas at twice the pressure for the same depth - constrained by lithostatic stresses), but
can be sufficient to potentially benefit CMM projects.
Cushion Gas: Cushion gas is the volume of gas needed to fill the storage facility to a point
where the pressure in the facility will provide a significant flow of gas when needed. During
normal storage operations, cushion gas volumes are not withdrawn. This volume is
recoverable, however, if operators reduce wellhead pressures to below normal facility
operating levels. Higher-volume facilities have larger cushion gas requirements. Therefore,
the sorption effect by remnant coal in an abandoned coal mine would increase cushion gas
requirements. Provided that the coals exhibit short diffusion times, and provided water
saturations remain constant, adsorbed cushion gas volumes should not impair facility
operations. If water saturations increase, or if coals exhibit long diffusion times, cushion gas
volumes are potentially unrecoverable. Gas present in remnant coals prior to facility
development may contribute toward the cushion gas volume.
Unrecoverable Gas: Natural gas storage facilities typically hold gas volumes that do not
contribute to facility pressurization. These volumes are termed unrecoverable gas, or lost
gas. At the Leyden facility, migrating gas volumes (approximately 115 mmcf (3.26 Mm3)
(derived from Hooker, 1990) are drawn to the facility during low pressure shut-in periods
implemented to assess inventory, and actually slowly increase facility pressure. These gas
volumes migrate to other formations and dissolve into the mine water at higher operating
pressures.
Facility Integrity During Pressure Cycling: Maintaining the structural integrity of the
subsurface space during facility operations is of concern because of frequent pressure
cycling. During gas injection periods, when gas pressures are increased from a low-pressure
condition, coal pillars are exposed to high initial effective stresses. Depending on permeability
and diffusion rates, pore pressures in the pillars should increase with increasing gas pressure,
and, therefore, effective stresses should decrease. With low-permeability coals or coals
exhibiting slow diffusion rates, gas injection would apply confining loads (compression) on the
pillars as surrounding gas pressures would significantly exceed the pore pressure. Such
loads should not impair the integrity of the pillars, although higher pore-pressure conditions
(relative to surrounding gas) during gas withdrawal may lead to pillar degradation.
Additionally, with large injection and withdrawal volume cycles (base load storage operations),
pressure loading and unloading of the facility may generate and propagate fractures that may
eventually lead to the deterioration of the gas seal. The magnitude and rate of facility
deterioration will depend on withdrawal and injection volumes and factors relating to the
stability of the mine openings, including permeability, and gas adsorption characteristics of the
remnant coal.
Impact of Preferential Sorption on Retrieved Gas Processing Requirements: The sorption
characteristics of coals to gases (carbon dioxide, nitrogen, water vapor, higher hydrocarbons,
and other gases) will impact the operations of an abandoned coal mine storage facility. The
adsorptive capacity of coals to various gases is illustrated in Figure 2.3. Laboratory research
clearly indicates that carbon dioxide and ethane are more sorptive than methane and that
nitrogen is less sorptive than methane. It also indicates that with gas mixtures, the most
sorptive gas is the last gas to desorb. This affects methane storage in abandoned coal mines
as follows:
During initial development of water-sealed facilities, operators should assume that
remnant coals will likely contain mostly nitrogen rather than methane, and that during
initial gas withdrawal, the coals will preferentially desorb nitrogen, increasing the
nitrogen concentration of the withdrawn gas. Operators should expect the
12
-------
concentration of nitrogen in withdrawn gas to decrease following subsequent injection
and withdrawal cycles.
Should the associated CMM project store gas with higher concentrations of carbon
dioxide, storage operators should expect an initial reduction of carbon dioxide
concentration in their withdrawn gas followed by a progressive increase in
concentration. Such operations would require an amine or comparable system of gas
enrichment. With this condition, operators could consider injecting higher
hydrocarbons that are more sorptive than methane (ethane, for example), which may
counter the negative impacts of carbon dioxide on the calorific value of the recovered
gas.
Should the associated CMM project elect to store gob gas, a mixture of air and
methane, storage operators should expect an increase in methane concentration in
the withdrawn gas.
In addition to the considerations discussed above, operators need to anticipate
dehydrating withdrawn gas.
gas pressure MPa
(1MPa = 145psi)
(1m3/t = 32cf/ton)
Figure 2.3: Adsorptive Capacity of a Coal for Two Inert Gases Relative to Methane
(McPherson, 1993)
2.1.2 Storage in Sealed Areas of Active Mines
Abandoned areas of active mines are not suitable for gas storage due to mine safety issues.
These issues include gas leakage and the potential for an explosive methane and air mixture in
mine ventilation air courses and gas inundation into the mine ventilation system resulting from
seal failure, mine entry instability, or pillar failure. Also, from a perspective of practical storage
13
-------
economics, this concept is difficult to implement because significant volumes of gas would be lost
through leakage with minimal sealed area pressurization.
This subsection: 1) presents the sealing practices for worked-out areas of active mines as per
federal regulations; 2) demonstrates why mine operators experience difficulties managing gas
exchange between sealed and active mine areas during natural barometric pressure changes and
how sealed area pressurization exacerbates this problem; and 3) demonstrates the magnitude of
gas loss anticipated with sealed area pressurization.
2.1.2.1 Sealing of Worked Areas
The U.S. Mine Safety and Health Administration (MSHA) requires sealing, or in certain cases
ventilation (CFR Title 30, Part 75.334, 1995), of abandoned or worked-out sections of active
mines. Coal mine operators seal worked-out sections with bulkheads constructed of solid and
flame retardant materials as per CFR Title 30, Part 75.335 (1995). The code presents
construction requirements for standard seals. For example, a standard seal requires solid
concrete block (6 in X 8 in X 16 in) (0.15 m X 0.20 m X 0.40 m) laid in mortar in the pattern
illustrated in Figure 2.4, hitched into the coal ribs and floor for a distance of 4 in (0.1 m), and
coated with appropriate flame retardant materials (flame spread index of 25 or less). Regulations
also require installation of gas sampling and water drainage pipes through the seal at specified
locations. Regulations allow alternative seal construction techniques (cementitious foam seals for
example), provided that seals withstand minimum static pressure loads of 20 psi (138 kPa).
It is a common misconception that seals eliminate leakage of air or gases between the abandoned
volume and the mine. In fact, mining engineers design seals to mitigate communication between
the two areas should an explosion occur on either side, and, in effect, they only retard or resist the
flow of air or gases exchanged between these areas. Gas exchange not only occurs through and
around the immediate area of the seal, but also through fractures within the roof and floor and coal
faces along the coal barrier pillars separating the two areas. In summary, gas exchange from
sealed areas is difficult to manage. The magnitude of this exchange depends on: 1) how the
abandoned sections interconnect with the system of ventilation (ventilation returns typically
manage gas emissions from sealed areas); 2) the volume of the sealed area; 3) the magnitude
and rate of changes in atmospheric pressure; and 4) the structural integrity of the mine openings
and seals with time.
Operators typically need to construct more than two seals (because of multiple connections) to
isolate a worked-out section from active mining areas.
2.1.2.2 Leakage Dynamics Between Sealed Areas and Mine Airways
Sealed, worked-out areas are reservoirs that contain air and methane mixtures. The void space
in the mined-out area and the effective porosity of the rubble and fracture 2:ones define the volume
of these reservoirs. Volumes can be very large as fractures may connect to permeable overlying
or underlying strata, including coals that also exhibit adsorptive storage capacity. But because
these volumes connect to active mine entries by (imperfect) seals and fractures, pressure
changes in the active mine workings impact their equilibrium pressures. The equilibrium static
pressure in the sealed areas continuously adjusts to equalize with the air pressure in the adjoining
mine entries. The greater the number of leakage paths, or the lower the resistance of the seals,
the more rapid is the pressure equalization process.
14
-------
Pilaster center
Transverse pattern
of laying block
Not to scale
Staggered block array
to strengthen pilaster
Figure 2.4: Standard Seal Construction as per CFR Title 30, Part 75.335
(Greningeretal., 1991)
The air pressure in adjoining mine entries varies with atmospheric pressure provided that the
ventilation system remains static (air density changes slightly affect fan operating performance).
For a well-sealed volume bounded by returns (seals vented by low resistance returns resulting in
minimal directional airflow in the sealed area), air and gas mixtures will tend to migrate from the
ventilation entry into the sealed volume with increases in atmospheric pressure. The pressure
difference between the ventilation entry (air pressure increasing with rising barometer) and the
sealed volume which is at a lower equilibrium pressure induces migration. Assuming rapid
diffusion and equilibrium within the sealed volume, air inflow into the sealed volume will increase
the overall gas density and therefore increase the static pressure within the volume. This process
continues with rising barometer, with the pressure in the sealed volume increasing, but lagging
behind the change in static pressure in the bounding ventilation entry. The more resistive (higher
resistance) the seals, the greater this time lag. During rising barometer periods, concerns arise
over the introduction of oxygen into sealed areas, potentially creating an explosive gas mixture.
When the reverse occurs (i.e. falling atmospheric pressure) gases flow out of the sealed volume
and into the ventilation entries, potentially raising methane in air concentrations over allowable
thresholds. Unfortunately, the greater the volume of the sealed area, the greater the magnitude of
leakage between sealed and active workings.
2.1.2.3 Example
Figure 2.5 illustrates the effect of barometric pressure fluctuations on the pressure in a sealed
volume as a function of time and number of seals (simulated by grouping seals in parallel). The
example assumes: 1) the total sealed volume is constant at 150 mmcf (4.27 Mm3); 2) ideal gas
conditions (all methane); 3) isothermal expansion and compression; 4) leakage is through very
15
-------
good standard seals with resistance of 89,400 P.U. (100,000 Ns2/m8) (as per tests conducted by
the U.S. Bureau of Mines (Greninger et al., 1991); 5) pressures inby and outby each seal is the
same (seals are in parallel); 6) there is no gas generation in the sealed area; and 7) there are no
adsorption or desorption effects in the sealed area.
Figure 2.5 clearly illustrates the increase in the time required for the sealed area to react to
pressure changes in the adjoining mine entries with an increase in seal resistance (reduced
number of seals). Figure 2.6 shows the cumulative volume of gas from the sealed area that would
be emitted into the bleeder entry during the simulated atmospheric pressure change, while Figure
2.7 illustrates the corresponding dilution airflow requirements (to 2 percent methane by volume).
29.550
29.500
Single Seal
Two Seals
Four Seals
Eight Seals
Pressure Outby Seals
29.100
16 20 24 28
Time in Hours
Figure 2.5: Sealed Area Pressure Variation with Changes in Atmospheric Pressure Outby for a
Number of Seals in Parallel (1 in. Hg = 3.38 kPa)
Note that in this example, although gas emissions into the ventilation entry can be readily diluted
to less than two percent by 57 kcfm (27 m3/s) with eight seals, more than 1.4 mmcfd (40,000 m3/d)
of methane migrates into the adjoining entries from the sealed area.
Operators can use various techniques to manage gas exchange between active mine works and
sealed areas, including using pressure balancing techniques involving sensor adjustable
regulators in the adjoining ventilation entries, and in extreme cases, by drilling venting boreholes
to the surface (Garcia et al., 1995). Some operations with severe seal emission problems
evacuate mining personnel during periods of falling barometer.
16
-------
1,800,000
1,600,000 .
1,400.000
j-j 1,200,000 ^J
in
£
=" 1,000,000
800,000
o, 600,000
400,000
200,000
Single Seal
_o_ Two Seals
ir- Four Seals
e Eight Seals
20 24 28
Time in Hours
Figure 2.6: Cumulative Leakage from Sealed Area with Changes in Atmospheric Pressure Outby for
a Number of Seals in Parallel (1 cf = .0283 m3)
70 .
60 .
so
- Single Seal
- Two Seals
- Four Seals
- Eight Seals
40 4
12
Time in Hours
Figure 2.7: Ventilation Requirements to Dilute Emissions from Seals to less than 2 Percent by
Volume during Atmospheric Pressure Changes (1 kcfm = 0.472 m3/s)
17
-------
Note that natural changes in barometric pressure are insignificant relative to pressure changes
that would be applied to sealed areas for gas storage purposes. The following section presents
analyses conducted to demonstrate the impacts of pressurization of sealed areas on leakage into
adjoining mine entries.
2.1.2.4 Sealed Area Pressurization
The first step in the analysis was to generate time-dependent plots assuming the same sealed
volume (150 mmcf or 4.27 Mm3) and general conditions described in the previous subsection.
The analysis assumes that operators inject methane into the sealed space to a pressure of one
atmosphere (14.7 psig or 101 kPa gauge pressure) at a constant rate over a 48-hour period and
that pressurization would allow storage of approximately 300 mmcf (8.5 Mm3) of methane. A seal
resistance of 1.8 x 10s P.U. (2.0 x 106 Ns2/m8) represents high integrity, 200 psi (1.4 MPa), 8 ft
(2.4 m thick) cementitious seals as tested by the U.S. Bureau of Mines (Greninger et al., 1991).
The analysis also assumes that the static pressure in the adjoining mine entry remains constant
during the pressurization process.
Figures 2.8 and 2.9 present the methane leakage through the seals and the corresponding
ventilation airflow requirements over the pressurization period (48 hours) and at steady state (one
atmosphere), respectively.
Figure 2.8 illustrates that with just one seal and storage pressures of only one atmosphere, gas
losses exceed 686 mcfd (19,416 m3 per day). This represents an annual loss of 1.6 times the
stored volume. Significantly greater gas losses and bleeder dilution requirements arise with the
more realistic scenario of four seals: methane leakage of 2.7 mmcfd (77,760 m3 per day), stored
volume losses of 55 percent per month, and ventilation dilution requirements of 190 kcfm (90
m3/s). This dilution requirement would likely strain ventilation systems at many mining operations.
Note that methane leakage from the slightly pressured (only one atmosphere gauge pressure),
well-sealed area (with high resistance seals) is approximately twice that predicted during a
naturally occurring barometric pressure change for a similar sealed area isolated by lower
resistance seals (prone to greater leakage). Increased sealed area pressurization, or greater
sealed area volumes, would result in increased leakage, increased gas losses, and
unmanageable ventilation requirements.
Also note that this example does not account for leakage through fractures which would also
increase both leakage magnitudes and dilution requirements. Additionally, the seal resistance
used in the example represents ideal conditions which would likely decrease with time due to
entry and seal integrity degradation. Pressure cycling of the sealed area during gas injection and
withdrawal activities would exacerbate seal degradation. In the example above, should sudden
seal failure occur, the mine could potentially be inundated by over 300 mmcf (8.5 Mm3) of
methane as it expands into the workings from the pressurized space.
Although using lower storage pressures, smaller stored volumes, and fewer seals would reduce
gas losses and dilution requirements, the benefits of small-volume gas storage capabilities would
likely not overcome mine concerns regarding uncontrolled gas leakage and potential
accumulations of explosive gas mixtures in mine entries.
18
-------
4000
3500
3000
Single Seal
_o- Two Seals
6 Four Seals
_e- Eight Seals
0 4 8 12 16 20 24 28 32 36 40 44 48 52 56 60 64 68 72
Figure 2.8: Methane Leakage through Seals during Injection Period and at Steady State
(1 cfm = .000472 m3/s)
400 -
350
300
-Single Seal
- Two Seals
- Four Seals
- Eight Seals
0 4 8 12 16 20 24 28 32 36 40 44 48 52 56 60 64 68 72
Figure 2.9: Ventilation Airflow Required to Dilute Methane Emissions from Seals during Injection
Period and at Steady State (1 kcfm = 0.472 m3/s)
19
-------
2.2 POTENTIAL FOR ABANDONED MINE GAS STORAGE NEAR THE 21 GASSIEST U.S. MINES
Many gassy mines are located near abandoned coal mines, some potentially suitable for coalbed
methane storage. Table 2.1 lists the top 21 gassy mines as identified by U.S. EPA in 1997, their
total estimated methane emissions (methane emissions from ventilation and degasification
systems) and their location by state and county (U.S. EPA, 1997).
Table 2.2 presents the recorded number of abandoned coal mines that exist in the same counties
as the top 21 gassy mines (U.S. DOI, 1993). The abandoned mines represent coal mine workings
abandoned after the year 1950 because of concerns about availability of records (abandoned
mine maps, locations of shafts, wells, etc.), and because of issues relating to physical
deterioration of the abandoned workings and their ability to contain injected gas (i.e. ability to
maintain a seal). This table merely presents a list of abandoned mines on record. U.S. EPA will
conduct further site-specific studies and will identify a short list of candidates for each region
based on site selection criteria derived from this report.
Mine Name
Blue Creek No. 7
Blue Creek No. 4
Blue Creek No. 5
Blue Creek No. 3
Oak Grove
Shoal Creek
Estimated Methane
Emissions (mmcfd)
30.7
21.3
9.9
24
21.5
8.3
Location
State
AL
AL
AL
AL
AL
AL
County
Tuscaloosa
Tuscaloosa
Tuscaloosa
Jefferson
Jefferson
Walker
Galatia No. 56
Wabash
8.9
4.7
IL
IL
Saline
Wabash
Cumberland
Enlow Fork
Emerald No. 1
Bailey
Mine 84
10.9
14.3
9.7
8.2
4.1
PA
PA
PA
PA
PA
Greene
Greene
Greene
Greene
Washington
VP No. 8
Buchanan No. 1
VP No. 3
2.5
30.2
13.9
VA
VA
VA
Buchanan
Buchanan
Buchanan
Pinnacle No. 50
Federal No. 2
Blacksville No. 2
Humphrey No. 7
Loveridge No. 22
21.4
14.3
10
7.7
7.3
WV
WV
WV
WV
WV
Wyoming
Monongalia
Monongalia
Monongalia
Marion
Table 2.1: Location of Top 21 Gassy Mines in the U.S. by State and County (U.S. EPA, 1997)
20
-------
State
and County
ALABAMA
Fayette
Jefferson
Shelby
Tuscaloosa
Walker
Number of Gassy Mines
2
3
1
Recorded Number of
Abandoned Coal Mines
0
19
9
0
2
ILLINOIS
Edwards
Gallatin
Hamilton
Lawrence
Richland
Saline
Wabash
White
Williamson
1
1
1
27
4
1
1
38
1
2
74
PENNSYLVANIA
Allegheny
Fayette
Greene
Washington
4
1
134
164
190
106
VIRGINIA
Buchanan
Dickenson
Russell
Tazewell
3
2,998
619
180
209
WEST VIRGINIA
Fayette
McDowel
Marion
Mercer
Monongalia
Preston
Raleigh
Summers
Wetzel
Wyoming
1
3
1
3,557
N/A
231
717
814
1,822
3,444
52
4
3,178
Table 2.2: Recorded Number of Coal Mines Abandoned Since 1950 by County
(U.S. DOI, 1993)
21
-------
2.3 OWNERSHIP OF CONTAINER SPACE FOR STORAGE IN ABANDONED MINES
A report prepared for U.S. EPA by Elizabeth A. McClanahan, entitled Legal Issues Related to
Coalbed Methane Storage in Abandoned Coal Mines in Virginia. West Virginia. Pennsylvania.
Utah. Colorado, and Alabama (U.S. EPA 1998b). examines the questions that surround
ownership of the abandoned mine space which a developer may wish to use for storage in those
states. The following are summaries and excerpts from her report.
2.3.1 Ownership Issues
The questions of ownership are complex.
Who owns the mineral-depleted container - the coal owner, the surface owner, or the gas
and oil rights owner?
Who owns cushion gas? In any storage facility, there must be a pocket or cushion of gas
in place in order to provide the pressure needed to operate the facility. Cushion or base
gas is the gas in the reservoir (abandoned mine) which is native to the reservoir and/or
injected into the reservoir. If the cushion gas is native coalbed methane (that is, gas
remaining in the mine) the importance of ownership issues concerning the coalbed
methane itself are apparent.
Separation of property rights fall into the following groups: 1) surface ownership; 2) coal
ownership; 3) gas ownership; 4) oil ownership; and/or 5) residual mineral ownership (minerals
other than coal, oil, and gas). Developers may have leased any of these ownership interests and
could then have created additional burdens upon the leasehold, such as overriding royalties,
production payments, working interests, joint venture agreements, farmouts, etc. Furthermore,
ownership interests may arise in various forms (e.g., life estates, remainders, possibilities of
reverter or reversion, etc.). Courts now determine the intent (if any) of individual lessees or estate
owners as to the ownership of coalbed methane and its containment space. The courts must also
decide whether the intent of the parties or legislators should be a factor in the coalbed methane
ownership determinations.
2.3.2 Coalbed Methane Ownership Arguments
One must first examine ownership claims on the coalbed methane itself.
The coal owner may claim coalbed methane as an inherent part of the coal and that coal seam
ownership includes ownership of the "gas" contained within it. The coal owner may further argue:
1) coalbed methane adsorbs onto the coal; 2) separation is not possible because the physical
bond between the coal and the coalbed methane is so close; and 3) the coal seam is the source
of and the reservoir for the coalbed methane.
The gas owner may argue that the chemical composition of coalbed methane is nearly identical to
that of natural gas and should be included with gas ownership. Another theory the gas owner
may espouse is that the right to produce coalbed methane from coal is the same as removing
natural gas from other unowned subsurface formations (i.e. the sandstone formation, which may
not belong to the gas estate owner). The plain meaning of "gas" appears to definitively include
coalbed methane. In contrast, "coal" commonly means a solid mineral, not a gas. The gas
owner may also argue: 1) recovery methods parallel that of natural gas; 2) the migratory nature of
22
-------
coalbed methane and natural gas is the same; and 3) reversion of the container space to the gas
owner once the coal is mined conveys a right to the gas (in cases where the gas owner is also the
surface owner). Only a few courts, however, have held that "gas" includes coalbed methane.
Finally, a surface owner may claim an interest in the coalbed methane, although this position is
clearly the weakest. After the removal of coal, in most jurisdictions, ownership of the container
space reverts to the surface owner (see 2.3.3 below). Therefore, a surface owner could claim that
since he owns the coal container space, he could claim the coalbed methane within that space.
This would be an insubstantial argument, easily countered by the mineral owner's argument
unless the coal and gas have been specifically severed.
2.3.3 Storage Container Ownership Claims and Court Holdings
2.3.3.1 Coal Owner
A few jurisdictions have held that the mineral owner is the owner of the container space. At least
one jurisdiction, however, has significantly limited such coal owner claims. In one recent case,
claims on the container space depended upon the fact that the mine was not exhausted or
abandoned.
2.3.3.2 Surface Owner
The majority of jurisdictions hold that the surface owner, not the mineral owner, owns the
container space once the mining company depletes or abandons production of the mineral
occupying the space. A justification for this approach is that underground storage rights are not
related to the use of the mineral interest.
The U.S. EPA analysis states that, in Virginia, the 1920 Clayborn v. Camilla Red Ash Coal
Company case settled the matter of ownership of container space of abandoned coal mines.
After removal of coal, ownership of the container space reverts to the grantor of the coal interest.
In Camilla Red Ash, the court interpreted a grant of "all the coal on, in or under" the land, "with the
right to mine and remove" the same in relation to ownership of the space created after removal of
coal. The court held that "[undoubtedly, the grantee of coal in place owns a corporeal
hereditament; but all the American authorities agree that the right of the grantee to use the space
left by the removal of coal terminates and the space reverts to the grantor when the coal has been
exhausted." The court reasoned that the reversion takes place because "the grantee has never at
any time had a corporeal estate in the containing walls, and that the conveyance carries the
estate in the coal only".
Thus, in Virginia, after the removal of coal, the ownership of the container space reverts to the
surface owner, at least in cases where the coal owner either reserved or was conveyed "all the
coal with the rights to mine and remove the same". However, in light of the increased importance
of coalbed methane development, there are no guarantees that dissimilar fact situations will result
in the same ownership interpretation by Virginia courts.
The U.S. EPA report indicates that "an important question not addressed by the court in Camilla
Red Ash was the point at which coal is considered to be exhausted. Is it exhausted once all the
coal that may be economically mined is removed? Additionally, what happens if the mine is
abandoned, but there are still recoverable reserves? What if new techniques are discovered that
provide a means for recovering coal previously thought to be unrecoverable?"
23
-------
In summary, the EPA analyses state that the following major issues concerning storage of
coalbed methane in abandoned mines should be addressed:
(1) Who has the power to grant storage rights?
(2) Who owns the abandoned mine and the container space that remains after the mineral
has been depleted?
(3) If ownership depends upon the mineral being depleted or no longer recoverable, when
is the mineral actually no longer recoverable, and who makes the determination?
The analyses conclude by stating that many questions related to the above three issues have not
been answered because precedents have not been established in the area of gas storage in
abandoned coal mines.
24
-------
3.0 CONCEPTUAL STORAGE FACILITY
This section presents a conceptual design for peak-load gas storage facilities at two abandoned
coal mines. In both cases, the design goal is to assist nearby CMM pipeline injection projects to
mitigate supply and demand problems:
Oversupply: During peak gas production periods, the facilities could store oversupply gas
(gas that the project cannot sell due to pipeline capacity or gas demand issues); and
during low gas production periods the facilities could compensate for the reduced supply
of gas from the project. In this case, the storage facilities dampen fluctuations in gas
volumes sent to the pipeline.
Peak demand: The conceptual facilities would allow the nearby CMM projects to increase
revenues during periods of peak gas demand.
3.1 CASE DEFINITION
3.1.1 The Abandoned Mines
The two storage facilities examined herein are within underground coal mines abandoned less
than 20 years ago. The design assumes that accurate mine maps and mine histories are readily
available, and that the mines exhibit characteristics suitable for gas storage, such as:
Mine workings are primarily room and pillar.
The mines have minimal interconnections to the surface (3 shafts, 4 boreholes) that
require sealing.
Mining activities had minimal impact on overlying strata (secondary mining or longwall
mining was not practiced).
Ground water inundates the mine workings.
The mine workings are overlain by a relatively impermeable and competent caprock.
The differences between the two facilities are their depths below the surface and the coals mined.
Facility A is a 1700 ft (520 m) deep abandoned Virginia Pocahontas No.3 coal mine, and Facility B
is an 800 ft (244 m) deep Pittsburgh seam mine.
3.1.2 Storage Capacity
The available underground void space for gas storage at both facilities is approximately 60 mmcf
(1.7 Mm3). Assuming both facilities operate at a maximum of 75 percent of hydrostatic pressure
at depth, Facility A has a free gas capacity of about 2 bscf (56.6 Msm3) and Facility B has a
capacity of 1 bscf (28.3 Msm3). Accounting for the gas adsorption capacity and general
characteristics of the Virginia Pocahontas and Pittsburgh coal seams, and assuming 50 percent
coal recovery, gas adsorption on remnant coal pillars only, and a 35 percent irreducible water
saturation, the additional storage capacity gained by adsorption at maximum operating pressures
25
-------
for Facilities A and B are 1.2 and 0.6 bscf (34.0 and 17.0 Msm3), respectively. Table 3.1
summarizes the storage characteristics of the two conceptual facilities.
Storage Characteristics
Depth Below Surface (ft / m)
Available Free Storage Space (mmcf / Mm3)
Maximum Operating Pressure (psia / MPa)
Adsorbed Volume at Max. Op. Press, (bcf / Mm3)
Maximum Gas Storage Volume (bcf/ Mm3)
Facility A
1,7007 745
60 / 1 .7
500 / 3.45
1.2/34.0
3.2 / 90.6
Facility B
800 / 244
60/1.7
250/1.72
0.6/17.0
1.6/45.3
Table 3.1: Conceptual Storage Facility Characteristics
3.1.3 Facility Performance Objectives
The analysis assumes that the storage facilities complement high production CMM projects and
have the ability to double project gas deliverability during peak periods. Facility A is designed for
peak withdrawals of 80 mmscfd (2.26 Msm3 d) with maximum injection rates of 40 mmscfd (1.13
Msm3d). Facility B is designed for a maximum of 40 mmscfd (1.13 Msm3d) withdrawal and 20
mmscfd (5.65 Msm3d) injection. Table 3.2 summarizes wellhead pressures and cushion gas
volumes calculated to determine facility compression requirements. The table also presents
maximum consecutive gas withdrawal days at the rates designated above, accounting only for
free gas. As a result of permeability and diffusion characteristics of coal, the adsorbed working
gas volumes indicated below are not immediately available to facility operators and therefore do
not contribute to the maximum number of consecutive withdrawal days.
Performance Characteristics
Maximum Wellhead Pressure (psia / MPa)
Minimum Wellhead Pressure (psia / MPa)
Cushion Gas (bscf/ Msm3)
Working Gas (bscf / Msm3)
Number of Consecutive Max. Withdrawal Days
Facility A
480 /3.31
150 /1.03
1.35/38.2
1.85 /52.4
16
Facility B
245 /"1 .69
50 70.35
0.45/12.7
1.15 732.6
18
Table 3.2: Facility Performance Characteristics
3.2 FACILITY CONFIGURATION
Figure 3.1 generally illustrates the configuration of the surface equipment, including the injection,
withdrawal, pumping, and monitoring wells for conceptual Facilities A and E5.
3.2.1 Shaft and Borehole Sealing
The conceptual facility designs assume that both Facilities A and B contain three shafts and four
boreholes. The shafts are 10 ft (3.05 m) in diameter and necessitate clearing plugging material
and debris, constructing a platform below an impermeable layer of strata, excavating a key, and
constructing a sealing system as per the design shown on Figure 2.2. The boreholes necessitate
26
-------
uncovering, clearing of fill materials, cutting the casing below the impermeable horizon,
constructing a key, and installing a sealing system similar to that for the shafts.
Dewatering
Wells
''--''injJWdl. Wells
Observation
Wells
Commercial Pipeline
Abandoned Mine Works
Dewatering
Wells
From CMM Project
Figure 3.1: Conceptual Storage Facility General Layout
3.2.2 Wells
Dewatering: The design assumes that both Facilities A and B use a total of three dewatering
wells at 5 inches (175 mm) in diameter equipped with conventional, electric-powered well pumping
equipment (sucker rod or Monyo pumps).
Observation: Both facilities use two observation wells at 4 inches (100 mm) in diameter. These
wells monitor facility conditions during dewatering and gas injection/withdrawal.
Injection and Withdrawal: The Facility A design assumes a total of six 7-inch (175 mm) diameter
injection and withdrawal wells. The Facility B design assumes four such wells.
3.2.3 Compression
Both facilities use two modular compression stations for the design; one for injection and
withdrawal, the other for compression to sales pressure.
27
-------
Facility A: The design assumes that the associated CMM project delivers gas to the injection and
withdrawal compressor sites at the facility at about 180 psia (1.24 MPa). The design assumes
that this gas is routed to the storage facility following initial compression at the CMM project. At
the storage facility, six 855 bhp (650 kW) compressors work to inject or withdraw gas at pressures
between 150 and 480 psia (1.03 to 3.31 MPa). The system delivers gas to the sales compressors
approximately 13,000 ft away (4,000 m) at a minimum pressure of 380 psia (2.62 MPa). Here,
four 1000 hp (750 kW) compressors increase the gas pressure to 800 psia for delivery into a
nearby commercial pipeline. Water separation occurs prior to compression, with further glycol
dehydration prior to injection into the sales line. The design further assumes that the facility's gas
fuels the compressors.
Facility B: The design for Facility B assumes proportional (based on facility operating pressure)
delivered gas conditions. It assumes that the associated CMM project delivers gas to the injection
and withdrawal compressor sites at about 75 psia (0.517 MPa), and that this gas is routed to the
storage facility following initial compression at the CMM project. At the storage facility, four 750
bhp (650 kW) compressors work to inject or withdraw gas at pressures between 75 and 245 psia
(0.52 to 1.69 MPa). The system delivers gas to the sales compressors approximately 13,000 ft
away (4,000 m) at a minimum pressure of 380 psia (2.62 MPa). Here, four 1000 hp (750 kW)
compressors increase the gas pressure to 800 psia for delivery into a nearby commercial pipeline.
Gas processing and compressor fuel assumptions are as assumed for Facility A.
3.2.4 Gas Transport
For both designs the project transports gas from the source of coal mine methane to the injection
and withdrawal compressor stations at a maximum distance of 13,000 ft (4,000 m) via a 6-inch
(150 mm) diameter steel pipeline.
Further, both designs assume that an 8-inch (200 mm) diameter 13,000 foot (4,000 m) steel line
transports the gas from the storage (withdrawal) compressor stations to the sales compressors.
3.2.5 Power
Both designs assume installation of a 13.2 kV power line, distance of approximately 20,000 ft
(6,000 m) to the storage site to operate the dewatering pumps, monitoring and control systems at
the injection/withdrawal and sales compression sites, and ancillary site facilities.
3.2.6 Water Storage and Disposal
The design assumes that both facilities store produced water from the abandoned mine workings
in a nearby water collection system originally developed for the mines when active.
3.3 FACILITY OPERATIONS
3.3.1 Phase I - Design and Testing for Containment
During this initial testing phase, both storage projects will drill three wells: one observation, one
pumping, and one injection. Operators will reduce the hydrostatic pressure in the underground
openings and will test for gas containment initially with air, and then with methane. Project testing
28
-------
will require monitoring of facility pressure through the observation well during initial dewatering
and concurrent gas injection.
By testing, operators will determine site injection requirements and verify gas containment within
the monitoring area. Operators will use information from the testing phase to refine facility
capacity calculations, facility operational characteristics, and design and cost estimates.
3.3.2 Phase II - Construction
For both projects, the second phase will involve sealing shafts and boreholes and slowly removing
water to expand the test area to ultimately include the entire underground volume. Although not
necessary for operation, for the scenario modeled below the facility design assumes that
operators only withdraw gas for sales from the facility after the facility is at capacity and
installation of all infrastructure is complete.
The design also assumes that testing, detailed engineering, sealing and installation takes two
years to complete.
3.3.3 Phase III - Operations
For both facilities, operations include continued dewatering and injection and withdrawal of gas, as
required. The economic evaluations for both facilities, presented in Section 4, assume full-scale
operations for a 10-year period using various levels of activity (i.e. number of maximum gas
withdrawal days per year).
3.4 FACILITY COSTS
3.4.1 Capital Costs
Tables 3.3 through 3.6, present capital costs for the initial testing and construction phases. The
estimated cost to develop proposed Facility A is approximately $2.43 per mscf ($85.82 per 1000
sm3) of total working gas (adsorbed and free gas). Estimated costs for Facility B are
approximately $3.26 per mscf ($115.13 per 1000 sm3) of total working gas.
29
-------
Design and Test for Containment, Facility A
Component
Engineering/Design
Site Assessment
Test Program Design
30% Level Storage Facility Design
Test Program
Site Preparation
Surveys and Permits
Road and Location
Water Containment
Drill and Complete Wells
Observation Well
Dewatering Well
Injection Well
Wellheads and Equipping
Dewatering Well
Injection Well
Gas Transport / Compression
Temporary Gas Supply Line
Test Comp Site Prep/lnst/Freight
Compressors
Monitoring and Testing Systems
Supplies and Support Equipment
Natural Gas for Containment Tests
Labor
Testing and Analysis
Total Phase 1 Costs
Make/Type
Geological/Hydrologies I/Storage
Test/De-Water/Air-Gas Injection
With Cost Estimate and Economics
3 Sites
Modify Existing Facilities
1- Cased to Target Depth
1- Cased to Target Depth
1- Cased to Target Depth
Pumping Unit
Fittings/Valves/Detonation Arrester
HOPE on surface
For Lease Compressors
Rental
Rental
Miscellaneous
From Pipeline or CMM project
Contractor with ODC's
Size
4 inch
5 inch
7 inch
6 inch
475 hp Max
3 Months
3 Months
3 Months
Quantity
3
3
1
1650
1650
1650
1
1
13000
2
2
1
1
20000
3
Installed Cost per Uni
I 2.500
S 2,000
$ 5.000
J 22.73
$ 25.76
J 27.27
S 25.000
S 10.000
$ 7.69
$ 20,000
$ 18,000
$ 15.000
$ 25.000
$ 2.50
$ 30,000
Total Cost
S 25,000
$ 30,000
S 60.000
S 7.500
S 6.000
S 5.000
$ 37,500
S 42.500
$ 45.000
$ 25,000
$ 10,000
S 100,000
S 40.000
$ 36.000
$ 15,000
$ 25,000
S 50.000
$ 90.000
$ 649,500
Table 3.3: Total Costs Estimated for Phase I Design and Containment Testing for Facility A.
Detailed Design and Construction, Facility A
Component
Englneering/Deslgn/Legal
Detailed Engineering and Cost Estimate
Permitting, etc.
Legal
Seal Shafts and Boreholes
Shafts
Boreholes
Drill and Complete Wells
Observation Wells
Dewatering Wells
Injection/Withdrawal Wells
Wellheads and Equipping
Dewatering Well
Iniection/Withdrawal Well
Gas Transport Lines
Transport to Sales
Gas Delivery. Distribution and Collection
Compressor Interconnection
Compressors
Injection/Withdrawal Compressors
Water Separation Unit
Monitor/Control/Supp. Systems
Sale Compressors
Dehydration Unit
Monitor/Control/Supp. Systems
Gas Metering System
Connection to Transmission Line
Power
lo.^ KV 10 oump.ana Dewaietlny Wellt
132kVto480 V
Metering
Miscellaneous
Water Containment and Discharge
Surface Facilities
Total Design and Installation
Make/Type
Contractor
1 0 ft diameter Shafts
1 - Cased to Target Depth
2- Cased to Target Depth
5- Cased to Target Depth
Pumping Unit
Fittings/Valves/Detonation Arrester
Steel
Steel
Steel Fittings and Valves
Site Prep/lnstallation/Freight
For Withdrawal
Injection/Withdrawal Compressors
Site Prep/lnstallation/Frejght
For Sales
For Sales
Main Meter Run
Overland Power Line
Transformers
Electrical
Improve Existing Facilities
Size
1700ft
1700ft
4 inch
5 inch
7 inch
8 inch
5 inch
6 inch
870 hp
1000hp
1 3.2 kV Line
Quantity
1
1
1
3
4
1650
3300
8250
2
5
13.000
16.000
6
3
2
4
4
2
1
1
20,000
2
1
Installed Cost per Uni
$ 200,000
S 50,000
$ 50,000
$ 240.000.00
$ 25.000.00
$ 22.73
$ 25.76
$ 26.36
$ 25,000
S 10.000
$ 18.46
$ 16.00
$ 60.000
$ 20.000
$ 50,000
$ 60,000
$ 75.000
S 50.000
$ 20,000
$ 30,000
$ 25
$ 2,500
$ 20.000
Total Cost
$ 200.000
S 50.000
$ 50,000
S 720.000
$ 100,000
$ 37,500
$ 85.000
$ 217.500
$ 50.000
$ 50.000
$ 240.000
$ 256.000
S 100,000
S 360.000
$ 60.000
S 100,000
$ 240,000
$ 300,000
S 100.000
S 20,000
S 30,000
S 150.000
S 5,000
S 20,000
$ 50.000
$ 250.000
$ 3,841,000
Table 3.4: Estimated Detailed Design and Construction Costs for Facility A.
30
-------
Design and Test for Containment, Facility B
Component
Engineering/Design
Site Assessment
Test Program Design
30% Level Storage Facility Design
Test Program
Site Preparation
Surveys and Permits
Road and Location
Water Containment
Drill and Complete Wells
Observation Well
Dewatering Well
injection Well
Wellheads and Equipping
Dewatering Wei)
Injection Well
Gas Transport I Compression
Temporary Gas Supply Line
Test Comp Site Prep/tnst/Freight
Compressors
Monitoring and Testing Systems
Supplies and Support Equipment
Natural Gas for Containment Tests
Labor
Testing and Analysis
Total Phase I Costs
Make/Type
Geokogicat/Hydroiogical/Storage
Test/De-Water/Air-Gas Injection
With Cost Estimate and Economics
3 Sites
Modify Existing Facilities
1- Cased to Target Depth
1- Cased to Target Depth
1- Cased to Target Depth
Pumping Unit
Fittings/Valves/Detonation Arrester
HOPE on surface
For Lease Compressors
Rental
Rental
Miscellaneous
From Pipeline or CMM project
Contractor with ODC's
Size
4 inch
5 inch
7 inch
6 inch
300 hp Max
3 Months
3 Months
3 Months
Unit
ft
ft
ft
ft
per unit
perunrt
mcf
Quantity
3
3
1
750
750
750
1
1
13000
2
2
1
1
20000
3
Installed Cost per Unit
$ 2,500
$ 2,000
$ 5,000
$ 22.73
$ 25.76
$ 27.27
$ 25,000
$ 10.000
$ 7.69
$ 20,000
$ 12,000
$ 15,000
$ 25,000
$ 2.50
$ 30.000
Total Cost
$ 25,000
$ 30,000
$ 60.000
$ 7,500
$ 6,000
$ 5,000
$ 17,048
$ 19.320
$ 20,453
$ 25,000
$ 10,000
$ 100,000
$ 40,000
$ 24,000
$ 15,000
$ 25,000
$ 50,000
$ 90,000
$ 569,320
Table 3.5: Total Costs Estimated for Phase I Design and Containment Testing for Facility B.
Detailed Design and Construction, Facility B
Component
Engineering/Design/Legal
Detailed Engineering and Cost Estimate
Permitting, etc.
Legal
Seal Shafts and Boreholes
Shafts
Bo reticles
Drill and Complete Wells
Observation Wells
Dewatering Wens
InjecUorVWItndrawal Wells
Wellheads and Equipping
Dewatering Well
Injection/Withdrawal Well
Gas Transport Unes
Transport to Sales
Gas Delivery. Distribution, and Collection
Compressor Interconnection
Compressors
Injection/Withdrawal Compressors
Water Separation unit
Monitor/Control/Supo. Systems
Sale Compressors
Dehydration Unit
Monitor/Control/Supp. Systems
Gas Metering System
Connection to Transmission Line
Power
13.2 kVto Comp.and Dewatehng Wells
13.2kVto4BO V
Metering
Miscellaneous
Water Containment and Discharge
Surface Facilities
Total Design and Installation
MakefType
Contractor
10 ft diameter Shafts
1- Cased to Target Depth
2- Cased to Target Depth
3- Cased to Target Depth
Pumping Unit
Fittings/Valves/Detonation Arrester
Steel
Steel
Steel Fittings and Valves
Site Prep/Installation/Freight
For Withdrawal
Injection/Withdrawal Compressors
Site Prep/lnstaliation/Freight
For Sales
For Sates
Main Meter Run
Overland Power Line
Trans tuimenj
Electrical
Improve Existing Facilities
Size
800
800
4 inch
5 inch
7 inch
8 inch
6 inch
6 inch
750 hp
1000 hp
1 3.2 kV Line
Unit
ft
ft
ft
ft
ft
ft
ft
ft
Quantity
1
1
1
3
4
750
1500
2250
2
3
13.000
16,000
4
2
2
4
4
2
1
1
20.000
2
1
Installed Cost per Unit
$ 200,000
$ 50,000
$ 50,000
$ 160,000.00
$ 25.000.00
$ 22.73
$ 25.76
$ 26.36
S 25.000
$ 10.000
$ 16.46
$ 16.00
$ 50.000
i 20.000
$ 50.000
$ 60.000
$ 75,000
$ 50,000
$ 20.000
$ 30.000
$ 25
$ 2,500
S 20,000
Total Cost
$ 200,000
$ 50,000
$ 50,000
$ 480.000
$ 100.000
$ 17,048
$ 38.640
$ 59.310
S 50.000
I 30.000
$ 240.000
$ 256.000
$ 100,000
S 200,000
S 40.000
$ 100,000
$ 240.000
S 300,000
$ 100.000
S 20.000
$ 30.000
$ 150.000
$ 5.000
J 20.000
I 50.000
$ 250.000
% 3,175,998
Table 3.6: Estimated Detailed Design and Construction Costs for Facility B.
31
-------
3.4.2 Operating Costs
Tables 3.7 and 3.8 present the operating costs for the two proposed storage facilities during
normal operations on a monthly basis. Note that these tables do not include costs incurred for
gas consumed by the injection/withdrawal and sales compressors, nor do they account for gas
transmission costs from the CMM project. Such costs vary with the number of injections and
withdrawals. The ensuing economic analyses account for these costs.
Monthly Operations, Facility A
Component
Infrastructure
Power/Water/Communications
Miscellaneous Office Support
Dewatering Units
Power Consumption
Maint. /Repair/Supplies
Water Collection and Disposal
Injection/Withdrawal
Injection/Withdrawal Compressors
Lease Compressors
Compressor Supplies
Compressor Maint/Repair
Sales Gas Compression
Injection/Withdrawal Compressors
Lease Compressors
Compressor Supplies
Compressor Maint JRepair
Dehydrator Supplies
Operations
Labor
Miscellaneous Supplies
Vehicles
G&A
Management
Insurance/Property Tax
Estimated Monthly Operating Expenses
Make/Type
Assumes 95% Operation for Period
Fueled by qas
Included with Lease
Fueled by gas
Service
Average 4 per shift x 2 shifts/day
With Expenses
1 Full Time
Basis
$.04/kW-hr
855 hp
1000hp
Included with Least
Burdened Labor
Wise
Burdened Labor
Unit
Month
Month
Month
Month
Month
per 13 mmscfd
Month
Month
per 20 mmscfd
Month
Month
Month
Month
Month
Month
$ 8,600
$ 2.000
Cost per Unit
$ 500
$ 1 ,000
$ 1,045
$ 500
$ 500
175mscfd
S 10,000
$ 1.000
204 mscfd
$ 13,000
$ 600
$ 250
S 5,160
$ 10,000
$ 600
$ 8.600
$ 2,000
Cost
S 500
$ 1 .000
$ 3,135
$ 1,500
$ 500
1 .05 mmscfd
S 60,000
S 6,000
81 6 mscfd
S 52.000
S 28,800
$ 1,000
$ 41.280
$ 10,000
S 2,400
$ 8,600
$ 2,000
S 217,215
Table 3.7: Monthly Operating Expenses for the Proposed Storage Facility A.
Monthly Operations, Facility B
Component
Infrastructure
Power/Water/Communications
Miscellaneous Office Support
Dewatering Units
Power Consumption
Uamt./Repair/Supphes
Water Collection and Disposal
Injection/Withdrawal
infectiOfVWtthdrawal Compressors
Lease Compressors
Compressor Supplies
Compressor Maint/Repair
Sates Gas Compression
Sales Compressors
Lease Compressors
Compressor Supplies
Compressor MaintJRepair
Dehydrator Supphes
Operations
Labor
Miscellaneous Supplies
Vehicles
G&A
Management
insurance/Property Tax
Estimated Monthly Operating Expenses
Make/Type
Assumes 95% Operation for Period
Fueled by gas
included with Lease
Fueled by gas
Service
Average 4 per shift x 2 shifts/day
With Expenses
1 Full Time
Basis
S.04/KW-hr
750 hp
1000 hp
Included with Lease
Burdened Labor
Wise
Burdened Labor
Quantity
3
3
4
4
4
4
4
4
4
8
1
4
1
1
Unit
Month
Month
Month
Month
Month
perSmmscf
Month
Month
per 20 mmscfd
Month
Month
Month
Month
Month
Month
$ 8,600
$ 2.000
Cost per Unit
S 500
$ 1,000
S 1.045
$ 500
S 500
153 mscfd
$ 9,000
S 800
204 mscfd
S 13.000
$ 600
$ 250
$ 5,160
* 10.000
$ 600
* 8.600
S 2.000
Cost
$ 500
$ 1,000
$ 3.135
$ 1,500
S 500
612 mscfd
$ 36.000
S 3.200
81 6 mscfd
$ 52,000
5 28,800
$ 1,000
$ 41,21)0
$ 10,000
$ 2.400
S 8,600
S 2.000
$ 190.415
Table 3.8: Monthly Operating Expenses for the Proposed Storage Facility B.
32
-------
4.0 CONCEPTUAL STORAGE FACILITY USE AND ECONOMICS
This section presents the mode of operation assumed for the two conceptual storage facilities and
the results of the economic evaluations.
4.1 MODE OF OPERATION
The analyses assume that the conceptual storage facilities presented in Section 3.0 operate as
peak-load facilities that sell surplus or unsold gas from associated CMM projects for later sale
during periods of peak gas demand. The facilities can accommodate frequent injection and
withdrawal of gas at varied volume flows.
Because they are self-standing and operate their own sales compressors, the facilities allow their
associated CMM projects to double gas sales during peak demand periods.
The analyses further assume the following facility operational characteristics (Facilities A and B):
The CMM projects own and operate the storage facility in coordination with the facilities.
Before withdrawing and selling any gas, the facilities must fill to capacity.
The facilities are operational after two years of testing, construction, and filling.
The facilities are charged in Year 2 for the cost of the cushion gas at the mean off-peak
gas price.
The facilities do not pay for working gas as this is oversupply gas from their associated
CMM projects.
Gas to fuel the compressors costs the facilities: 1) the mean off-peak price for fuel
required for the injection and gas transport (from CMM project to storage facility)
compressors, and 2) the mean peak price for fuel required for the withdrawal and sales
compressors.
The facilities lose approximately 10 percent of their working gas per year through leakage,
migration, and diffusion into containment water.
The facilities are replenished with the same volume of gas withdrawn and lost during any
operating year.
A cycle involves withdrawing gas at maximum sustained rates (maximum withdrawal day:
80 mmscf (2.27 Msm3) per day for Facility A, and 40 mmscf (1.13 Msm3) for Facility B)
and subsequent filling.
The facilities sell gas at peak demand prices.
The facilities operate with the same average number of maximum withdrawal days per
year for 10 years (20 to 40 cycles per year). The analyses assume that the cushion gas
volumes are not withdrawn during the 10-year period of operation.
4.2 ECONOMIC ANALYSES
This subsection presents the economic analyses of the proposed storage facilities for a range of
maximum withdrawal days per year and average annual peak gas prices.
33
-------
4.2.1 Technical Assumptions
The economic analyses consider the following:
Gas Quality: For all scenarios, the storage facilities sell pipeline quality gas with an energy value
of 1000 Btu per scf (27.26 MJ/sm3).
Off-Peak Gas Pricing: A current 1998 off-peak gas sales price of $2.25 per mscf ($79.46 per
1000 sm3) was assumed at the injection point along the nearby commercial pipeline.
Peak Gas Pricing: During the winter periods in 1997, peak average monthly gas prices were as
high as $4.00 per mscf ($141.26 per 1000 sm3) (see Figure 1.2). Daily and weekly spot gas
prices were as high as $8.00 per mscf ($282.52 per 1000 sm3). Economic evaluations cover a
range of average annual peak gas prices between $2.50 and $4.00 per mscf ($88.29 to $141.26
per 1000 sm3). The maximum peak average price depends on the average number of maximum
withdrawal days per year; the greater the number of maximum withdrawal days, the lower the
maximum peak average price.
Gas Price Escalation: Gas prices will escalate at four percent per year, nominally, but stay flat in
real terms (EIA, 1997; CO2 constraints incorporated in El A projections).
Project Life: A 12-year project period was assumed: two years of testing, filling, and construction;
and ten years of operation.
Cost Contingency: A contingency of 15 percent was applied to the capital and operating costs
presented in Section 3.
Operating Costs: Operating costs were assumed to escalate by four percent per year.
Project Structure: The facilities were assumed to pay a royalty of 18.75 percent of net revenues
to claimants of the coalbed methane and underground storage container rights.
4.2.2 Financial Assumptions
The economic analyses reflect the following discount and tax rates and accounting practices:
Discount Rate: A nominal discount rate of 15 percent was assumed.
Tax Rate: A book-blended tax rate of 40 percent was used. This includes all applicable state and
federal corporate taxes, severance, and local taxes.
Depreciation: All tangible assets purchased by the project during the first two years depreciate at
double declining rates over 7 years.
Amortization of Expenses: All non-well-drilling expenses incurred by the project during the first
two years are amortized and expensed over the 10-year operating period. Well-drilling expenses
are amortized using the units of production method; expenses are distributed over the operating
period based on gas volume withdrawn from the facility.
Net Operating Losses: All net operating losses incurred during the operating years carry forward
until absorbed by taxable income.
34
-------
4.2.3 Results
The analyses developed cash flow statements and calculated the internal rate of return (IRR), net
present value (NPV) at the nominal discount rate of 15 percent, and project pay-back period for
permutations of maximum withdrawal days per year and average annual peak gas sales price.
Table 4.1 presents the scenarios evaluated for the two facilities. The first column contains
average annual first-year peak gas prices.
Average Peak Gas Price
$/mscf($/1000sm3)
$2.50 ($88.29)
$2.75 ($97.1 2)
$3.00 ($105.94)
$3.25 ($11 4.77)
$3.50 ($123.60)
$3.75 ($132.43)
$4.00 ($141. 26)
Average Number of Maximum Withdrawal Days Per Year
20
X
X
X
X
X
X
X
25
X
X
X
X
X
X
30
X
X
X
X
X
X
35
X
X
X
X
X
X
40
X
X
X
X
X
Table 4.1: Scenarios Evaluated by Analyses for Both Facilities A and B.
Cash Flow Statement
Tables 4.2 and 4.3 present the cash flow statements for 35 maximum withdrawal days and $3.50
per mscf ($123.60 per 1000 sm3) mean peak gas price for Facilities A and B, respectively.
Omitted are the cash flow statements for the other scenarios, but their economic indicators appear
in graphic format in Figures 4.1 through 4.6.
35
-------
CASH FLOW STATEMENT
Facility A
Revenue and Expenditures
Revenue
Capital Expenditures
Operating Expenses
Royalties
Gross Margin
Taxes
Depreciation and Amortization
Loss Carry Forward
Taxable Income
Corporate Tax
Cash Flow Adjustment
Plus Depreciation
Plus Loss Carry Forward
Cash Flows
Net Cash Flow
Net Cum Cash
Years
0.1875%
40%
Economic Indicators
Internal Rale of Return
Net Present Value 15%
Pay Back Period (Years)
34%
$ 8,890,760
2.5
1
$ 4,055.755
$ (4.055,755)
$ (4,055.755)
$ (4,055.755)
2
$ 6,971.619
$ (6,971,619)
$ (6.971,619)
$ (11,027.374)
3
$ 10,599,680
$ 4,352.957
$ 19.874
$ 6,226,849
$ (1.088.549)
$
$ 5,138.300
$ (2,055,320)
$ 1.088,549
$
$ 4,171.529
$ (6,855.846)
4
$ 11,023,667
$ 4,523.437
$ 20,669
$ 6,479,561
$ (996,350)
$
$ 5,483,211
$ (2,193,284)
$ 996,350
$
$ 4,286,276
$ (2,569.569)
5
$ 11,464,614
$ 4,700,736
$ 21,496
$ 6,742,381
$ (930.493)
$
$ 5,811,888
$ (2,324,755)
$ 930.493
$
$ 4,417,626
$ 1.848.057
6
$ 11,923,198
$ 4,885,128
$ 22,356
$ 7,015,715
$ (883.453)
$
$ 6,132.262
$ (2.452,905)
$ 883,453
$
$ 4,562,810
$ 6.410,867
7
$ 12,400,126
$ 5,076,895
$ 23,250
$ 7,299,982
$ (849,853)
$
$ 6,450,129
$ (2.580.052)
$ 849,853
$
$ 4,719.930
$ 11,130,797
8
$ 12.896,131
$ 5.276,332
$ 24,180
$ 7.595,619
$ (821,177)
$
$ 6,774,442
$ (2,709,777)
$ 821,177
$
$ 4,865,842
$ 16,016.639
9
$ 13,411,977
$ 5,483,747
$ 25,147
$ 7,903,082
$ (765,852)
$
$ 7,137.230
$ (2,854,892)
$ 765,852
$
$ 5,048,190
$ 21.064,830
10
$ 13.948,456
$ 5,699,459
$ 26,153
$ 8,222,843
$ (765.852)
$
$ 7,456.991
$ (2.982,797)
$ 765.852
$
$ 5.240.047
$ 26,304,876
11
$ 14,506,394
$ 5,923,799
$ 27,199
$ 8,555,395
$ (765,852)
$
$ 7,789,543
$ (3,115,817)
$ 765,852
$
$ 5,439,578
$ 31,744.455
12
$ 15,086,650
$ 6,157,113
$ 28,287
$ 8,901,249
$ (765,852)
$
$ 8,135,397
$ (3.254,159)
$ 765,852
$
$ 5.647,090
$ 37,391,545
Table 4.2: Facility A, Cash Flow Statement for 35 Maximum Withdrawal Days and $3.50 per mscf ($123.60 per 1000 sm3) Average Peak Gas Sales Price
-------
CASH FLOW STATEMENT
Facility B
Revenue and Expenditures
Revenue
Capilal Expenditures
Operating Expenses
Royalties
Gross Margin
Taxes
Depreciation and Amortization
Loss Carry Forward
Taxable Income
Corporate Tax
Cash Flow Adjustment
Plus Depreciation
Plus Loss Carry Forward
Cash Flows
Net Cash Flow
Net Cum. Cash
Years
0.1875%
40%
Economic Indicators
Internal Rate of Return
Net Present Value 15%
Pay Back Period (Years)
15%
$ 80.936
4.9
1
$ 2,709,010
$ (2,709,010)
$ (2,709,010)
$ (2,709,010)
2
$ 4,663,600
$ (4,663,600)
$ (4,663,600;
$ (7,372,610)
3
$ 5,299,840
$ 3,355.623
$ 9.937
$ 1,934,280
$ (758,618)
$
$ 1,175,661
$ (470,265)
$ 758,618
$
$ 1.464,015
$ (5.908,594)
4
$ 5,511,834
$ 3,488.625
$ 10,335
$ 2,012,874
$ (673,539)
$
$ 1,339,335
$ (535,734)
$ 673,539
$
$ 1,477,140
$ (4,431,454)
5
$ 5,732,307
$ 3.626.947
$ 10.748
$ 2,094,612
$ (612.769)
$
$ 1,481,844
$ (592,737)
$ 612,769
$
$ 1,501,875
$ (2,929,580)
6
$ 5,961,599
$ 3,770,801
$ 11,178
$ 2,179,620
$ (569.361)
$
$ 1,610,259
$ (644,104)
$ 569,361
$
$ 1,535,516
$ (1,394,063)
7
$ 6,200,063
$ 3,920,410
$ 11,625
$ 2,268.028
$ (538,356)
$
$ 1,729.672
$ (691,869)
$ 538,356
$
$ 1.576,159
$ 182,096
8
$ 6,448,066
$ 4.076.003
$ 12.090
$ 2,359,972
$ (512,088)
$
$ 1,647,884
$ (739,154)
$ 512,088
$
$ 1,620,818
$ 1,802.914
9
$ 6,705,988
$ 4.237.820
$ 12,574
$ 2,455.594
$ (460,842)
$
$ 1,994,752
$ (797,901)
$ 460,842
$
$ 1,657,693
$ 3.460.607
10
$ 6.974,228
$ 4,406,110
$ 13.077
$ 2,555,041
$ (460.842)
$
$ 2,094,199
$ (837,680)
$ 460,842
$
$ 1,717,361
$ 5,177,969
11
$ 7,253,197
$ 4,581,131
$ 13,600
$ 2,658,466
$ (460.842)
$
$ 2,197,624
$ (879,050)
$ 460,842
$
$ 1,779,416
$ 6,957.385
12
$ 7,543,325
$ 4,763,153
$ 14,144
$ 2,766,028
$ (460,842)
$
$ 2.305,186
$ (922,074)
$ 460.842
$
$ 1,843.953
$ 8.801.339
Table 4.3: Facility B, Cash Flow Statement for 35 Maximum Withdrawal Days and $3.50 per mscf ($123.60 per 1000 sm3) Average Peak Gas Sales Price
37
-------
Economic Indicators, Facility A
Figures 4.1 through 4.3 summarize three economic indicators for the deeper, higher operating
pressure storage facility in the abandoned Virginia Pocahontas 3 coal searn mine (i.e., Facility A):
IRR, NPV at 15 percent, and project pay-back period for all of the project operations scenarios
analyzed.
50%
45%
40%
35%
_ 30%
o:
* 25%
u .
t
°- 20%
15%
10%
5%
0%
1
-O- 20 Max Wdl Days
-0-25 Max Wdl Days
A30 Max Wdl Days
-X-35 Max Wdl Days
"1 X40 Max Wdi Days
$2.50 $2.75 $3.00 $3.25 $3.50 $3.75
Average Annual Peak Gas Price (in First Year $) S/MSCF
$4.00
$4.25
Figure 4.1: IRR for Conceptual Storage Facility A as a Function of Mean Annual Gas Sales Price
and Number of Maximum Withdrawal Days Per Year ($1 per mscf = $35.315 per
1000sm3)
38
-------
9.00
8.00
1 -D-20MaxWdlDays
-0-25 Max Wdl Days
-6- 30 Max Wdl Days
-X-35 Max Wdl Days
-*f- 40 Max Wdl Days
1.00
$2.50 $2.75 $3.00 $3.25 $3.50 $3.75
Average Annual Peak Gas Price (in First Year $) $/MSCF
$4.00
$4.25
Figure 4.2: Pay-Back Period for Conceptual Storage Facility A as a Function of Mean Annual Gas
Sales Price and Number of Maximum Withdrawal Days Per Year ($1 per mscf = $35.315
perl 000 sm3)
12,000
-D-20 Max Wdl Days
-0-25 Max Wdl Days
-a-30 Max Wdl Days
X35 Max Wdl Days
-X-40 Max Wdl Days
(4,000)
$2.50 $2.75 $3.00 $3.25 $3.50 $3.75
Average Annual Peak Gas Price (in First Year $) S/MSCF
$4.00
$4.25
Figure 4.3: NPV for Conceptual Storage Facility A as a Function of Mean Annual Gas Sales Price
and Number of Maximum Withdrawal Days per Year ($1 per mscf = $35.315 per 1000
39
-------
Economic Indicators. Facility B
Figures 4.4 through 4.6 summarize three economic indicators for the shallower, lower operating
pressure storage facility in an abandoned Pittsburgh coal seam mine (i.e., Facility B): IRR, NPV
at 15 percent, and project pay-back period for all of the project operations scenarios analyzed.
25% .
-tt- 30 Max Wdl Days
-X-35 Max Wdl Days
-X- 40 Max Wdl Days
0%
$2.50 $2.75 $3.00 $3.25 $3.50 $3.75
Average Annual Peak Gas Price (in First Year $) S/MSCF
$4.00
$4.25
Figure 4.4: IRR for Conceptual Storage Facility B as a Function of Mean Annual Gas Sales Price and
Number of Maximum Withdrawal Days Per Year ($1 per mscf = $35.315 per 1000 sm3)
40
-------
j -ft- 30 Max Wdl Days
-X-35 Max WdlDays
-*- 40 Max Wdl Days
3.00
$2.50 $2.75 $3.00 $3.25 $3.50 $3.75
Average Annual Peak Gas Price (in First Year S) S/MSCF
$4.00
$4.25
Figure 4.5: Pay-Back Period for Conceptual Storage Facility B as a Function of Mean Annual Gas
Sales Price and Number of Maximum Withdrawal Days Per Year ($1 per mscf = $35.315
perl 000 sm3)
o
0
re
re
£
0-
1 /
)
>
>
/ /
/
s
-A- 30 Max Wdl Days
, ! -X- 35 Max Wdl Days
-X-40 Max Wdl Days
>/ A
/
1
^
/
$2.50 $2.75 $3.00 $3.25 $3.50 $3.75 $4.00 $4
Average Annual Peak Gas Price (in First Year $) J/MSCF
Figure 4.6: NPV for Conceptual Storage Facility B as a Function of Mean Annual Gas Sales Price
and Number of Maximum Withdrawal Days per Year ($1 per mscf = $35.315 per 1000
41
-------
4.3 SUMMARY OF ECONOMIC ANALYSES
As anticipated, the analyses show that the economics of the proposed facilities improve with
increased gas sales (i.e. increased number of maximum withdrawal days) and increased peak
gas sale prices. The analyses indicate that the deeper, higher-capacity facility (Facility A) earns
greater returns with fewer cycles (maximum withdrawal days) than the shallower, lower-pressure
facility (Facility B). Facility A earns returns greater than 15 percent if the facility cycles more than
30 maximum withdrawal days worth of gas per year for mean annual peak gas prices greater than
$2.75 per mscf ($97.12 per 1000 sm3). This amounts to 2.4 bscf (67.96 Msm3) in annual gas
sales. At this level of performance, pay-back of initial investments is within 5 years, or half of the
modeled project operating life. Facility B only earns returns of greater than 15 percent if the
facility cycles more than 35 maximum withdrawal days for mean annual peak gas sales prices of
greater than $3.50 per mscf ($123.60 per 1000 sm3).
Using minimum economic operating parameters of 25 maximum withdrawal days per year at an
average annual peak gas sales price of $3.25 per mscf ($114.77 per 1000 sm3), the calculated
operating cost of Facility A per cubic foot of sales gas, accounting for compression, is $1.98 per
mscf ($69.92 per 1000 sm3). For gas storage facilities, operating costs decrease with increased
cycles per year. For example, the design's operating cost for the maximum cycles simulated (40
maximum withdrawal days per year) drops to $1.41 per mscf ($49.79 per 1000 sm3).
Comparatively, Facility B's operating costs for minimum economic operating parameters (35
maximum withdrawal days at mean annual peak gas sales prices of greater than $3.50 per mscf
($123.60 per 1000 sm3)) are $2.39 per mscf ($84.40 per 1000 sm3).
Note that the analyses assume that the working gas in the facilities is unsold oversupply stock
from the associated CMM project. The analyses do not account for the cost of producing the
supply gas, but consider only the cost of gas transfer to the storage facility, injection, storage, and
sale. Thus, the analyses may indicate a viable project even with gas priced at mean off-peak
levels, given a sufficient number of cycles per year. Overall, the analyses show that with
favorable gas pricing and high gas demand, high-capacity abandoned mine storage facilities could
earn large returns and pay for themselves in a relatively short period of time.
42
-------
5.0 CONCLUSIONS
This report discusses two abandoned coal mine gas storage concepts: storage in abandoned
mines and storage in abandoned areas of active mines. For the latter case, the report illustrates
the problems associated with gas containment and leak-off in active mines, as well as the
problems faced by coal mine operators during periods of rising barometer. For storage in
abandoned mines, the report presents a conceptual design and economic study to demonstrate
the worth of such facilities in conjunction with large CMM projects. Summarized below are the
results of the analyses for these two concepts.
5.1 GAS STORAGE IN ABANDONED COAL MINES
In addition to presenting technical issues relating to containment of gas under pressure in
abandoned coal mines and the experience with this technique in the United States, the report
discusses how gas storage would benefit coalbed methane projects that inject gas into
commercial pipelines. Specifically, these facilities can: 1) provide project operators with the
ability to store oversupply gas, and can, therefore, stabilize gas flows and increase gas sales
volumes; and 2) provide for increased revenues by selectively injecting gas into the commercial
pipeline during periods of peak gas demand. The report evaluated two hypothetical storage
facilities for use in conjunction with large CMM projects, formulated facility operating modes, and
performed economic analyses.
5.1.1 Technical Issues Relating to Storage
Abandoned coal mine workings must have favorable characteristics for storage and may provide
additional enhanced capacity by adsorption effects. Presented below is a summary of
considerations for site selection.
Abandoned coal mines favorable for gas storage generally:
Are deeper than 1000 feet below the surface.
Are within undisturbed surrounding strata (e.g., room and pillar without extensive
secondary recovery rather than longwall).
Have been abandoned within the last 50 years.
Have available detailed records of mining activities.
Have competent and impermeable immediate overlying strata.
Have conducive hydrogeologic conditions to provide a water seal for the gas.
Have few connections to the surface (shafts, wells, etc.).
Were developed in coals with preferable permeability and adsorption characteristics (high
gas storage capacity and short diffusion rates).
Can serve a large-scale CMM project or several projects.
43
-------
5.1.2 Experience in Abandoned Coal Mine Storage
One successful facility, developed in an abandoned sub-bituminous mine in the Denver, Colorado
area, operates in the United States. A water seal and impermeable cap rock provides gas
containment.
Overseas experience is limited to two facilities operating in Belgium, where operators first allowed
desorbing methane to purge the abandoned mine workings before injecting pipeline gas. These
mines are dry and large adsorptive effects significantly increase their storage capacity. The
storage facilities operate at very low pressures.
5.1.3 Conceptual Facilities
The analyses show that select abandoned coal mines could be suitable for gas storage and could
provide significant economic advantages to coalbed methane projects. Relative to lower cost,
conventional depleted gas reservoirs and aquifer storage facilities, abandoned coal mine storage
volumes are much smaller, but development costs are generally comparable per cubic measure of
working gas. An estimate of the development cost (capital plus working gas) of the deep, larger
capacity facility presented in the report (Facility A) is approximately $5.96 per mscf of working gas
($210.48 per 1000 sm3). In comparison, conventional depleted reservoir storage facilities cost
between $2 and $4 per mscf of working gas ($70.63 to $141.25 per 1000 sm3), and mined salt
domes between $7 and $14 per mscf ($247.20 to $494.40 per 1000 sm3) of working gas,
respectively (Beckman and Determeyer, 1997). As a result of comparable development costs and
lower storage capacities, the shallower facility presented in this report (Facility B) is slightly
costlier, at $6.41 per mscf of working gas ($226.38 per 1000 sm3).
5.1.4 Conceptual Facility Economics
The analyses show that abandoned mine gas storage can be particularly advantageous to larger
coalbed methane projects where gas markets and prices fluctuate. Estimates of abandoned mine
storage facility operating costs are comparable to conventional facilities when they are cycled
frequently. The estimates predict operating costs between $1.41 and $1.98 per mscf ($49.79 to
$69.92 per 1000 sm3) of gas sales depending on the number of maximum withdrawal days (for
Facility A). The analyses predict single-cycle (all working gas volume cycled in one year)
operating costs for Facilities A and B of $2.09 and $2.80 per mscf of sales gas ($73.81 and
$98.88 per 1000 sm3), respectively. Conventional storage facilities operate at between $0.20 and
$4.50 per mscf ($7.06 to $158.92 per 1000 sm3) of gas sales on a single-cycle basis (Beckman
and Determeyer, 1997).
Figure 5.1 presents the IRR projected for a peak-load facility that can withdraw gas at 80 mmscf
(2.265 Msm3) per day (defined as one maximum withdrawal day) for a range of maximum
withdrawal days per year and average annual peak gas sales prices. These simulations are for a
high-capacity, high-pressure facility (500 psia (3.45 Mpa)) that operates in conjunction with a
large-scale CMM project and stores oversupply gas; the facility does not pay for the injected gas.
The studies show IRRs of greater than 15 percent with a minimum of 30 maximum withdrawal
days per year for average annual 1998 peak gas prices of $2.75 per mscf ($97.12 per 1000 sm3).
44
-------
50%
45%
40%
35%
30%
15%
10%
0%
T"
-O- 20 Max Wdl Days
-O- 25 Max Wdl Days
-&- 30 Max Wdl Days
-X-35 Max Wdl Days
-X-40 Max Wdl Days
$2.50 $2.75 $3.00 $3.25 $3.50 $3.75
Average Annual Peak Gas Price (in First Year S) S/MSCF
$4.00
$4.25
Figure 5.1: IRR for the Conceptual Storage Facility (A) as a Function of Gas Sales Price and Number
of Maximum Withdrawal Days per Year
5.2 GAS STORAGE IN SEALED AREAS OF ACTIVE MINES
The analyses and examples illustrate that this option is unable to contain gas in typical "sealed
areas" of active mines. Even when operators use the best practices, "sealed" areas will not
adequately contain gas pressurized to the extent required for storage. Typical sealed areas in
coal mines, for example, connect to active mine workings through a multitude of leakage paths in
or surrounding the seals (stoppings or bulkheads) and through fractures in the coal or in overlying
or underlying strata. In fact, gases from sealed mined-out areas leak into active mine entries
during natural increases in barometric pressure. These natural pressure changes are relatively
small. For example, a pressure increase of 0.4 inches of Hg (1.3 kPa) is not uncommon over a
24-hour period in some areas. This represents an increase in atmospheric pressure of only 1.28
percent, whereas pressurization to many atmospheres for storage purposes is common practice.
The analyses show that for a sealed area isolated by only one high-integrity seal (actually
achieving high seal integrity is very rare in mining) and pressured to one atmosphere, leak-off
rates (i.e., gas losses to the adjacent active mine workings) would be substantial. With four or
more seals (a more likely scenario), this pressurization would cause unacceptable gas emissions
into mine workings, resulting in methane levels that could not be adequately diluted to required
limits by the mine's ventilation system. Furthermore, safety concerns (e.g., potential seal failure
and inundation of the active workings with stored gas) preclude further consideration of this
concept, except possibly for areas in mines specifically constructed for this purpose.
45
-------
5.3 RECOMMENDATIONS FOR FURTHER STUDY
This report indicates that establishing a large, high-pressure abandoned mine gas storage facility
may be a feasible and very worthwhile project. The report also illustrates that a medium-size
(over 1 bcf (28.3 Msm3)), lower-pressure (250 psia (1.723 Mpa)) facility can be economic
depending on gas demand and associated CMM project size. Possible additional studies of gas
storage facilities covering a range of project sizes and gas uses include the following:
It may be appropriate to examine a range (small to large) of power projects that operate in
conjunction with a gas storage facility to take advantage of on-peak pricing. Coalbed
methane projects normally must run continuously to match continuous gas drainage. If
the operator could divert the gas to storage during off-peak times (nights and weekends),
it would be possible to generate during peak hours at effectively double the normal flow
rate by simultaneously withdrawing gas from storage. As with pumped storage facilities
used by utilities, off-peak gas storage will consume some of the available energy with its
gas-driven compressors. The economic justification for such a project will depend entirely
on the peak versus off-peak price differentials available from the customer.
Another possible permutation of the storage concept is a project selling gob gas to a local
industry that: 1) operates only one shift; and 2) is able to consume gas at a rate greater
than the mine's flow rate from the degasification system. Gas would enter storage during
nights and weekends and re-enter the dedicated pipeline to the user during working
hours.
U.S. EPA has initiated a study to identify closed or abandoned underground coal mines
that offer the potential to be used as CMM storage sites. That initiative involves the
following component activities: site screening, candidate site characterization, preliminary
economic analysis, and preparation of site briefs. The briefs will identify the potential
candidate storage sites, address the relative advantages and disadvantages of each
candidate site on a technical and economic basis, and present a summary of cost and
economics for each site.
46
-------
6.0 REFERENCES
American Gas Storage Survey, 1997, A.G.A. Home Page: http: //www.aga.com/. Gas Industry
Online: Current Stats and Studies, downloaded May 12, 1997.
Beckman, J.L. and Determeyer, P.L., 1997, "Natural Gas Storage: Historical Development and
Expected Evolution", Gas Research Institute, "Gas Tips", Spring, 1997.
CFR, 1995, U.S. Code of Federal Regulations, Title 30, Mineral Resources, Parts 1 to 1999, July
1, 1995.
Dusar, M., and Verkaeren, 1991, "Methane Desorption in Closed Collieries: Examples from
Belgium", ECE Workshop on the Recovery of Coalbed Methane.
EIA, 1997, Short-Term Energy Outlook. Quarterly Projections. First Quarter 1997. U.S.
Department of Energy, Energy Information Administration, Office of Energy Markets and End Use,
Washington, DC.
EIA, 1996, Short-Term Energy Outlook. Quarterly Projections. First Quarter 1996. U.S.
Department of Energy, Energy Information Administration, Office of Energy Markets and End Use,
Washington, DC.
EIA, 1995, Short-Term Energy Outlook. Quarterly Projections, First Quarter 1995. U.S.
Department of Energy, Energy Information Administration, Office of Energy Markets and End Use,
Washington, DC.
EIA, 1994, Short-Term Energy Outlook. Quarterly Projections. First Quarter 1994. U.S.
Department of Energy, Energy Information Administration, Office of Energy Markets and End Use,
Washington, DC.
Garcia, F., McCall, F.E., and Trevits, M.A., 1995, "A Case Study of Methane Gas Migration
Through Sealed Mine Gob Into Active Mine Workings", Proceedings of the 7th U.S. Mine
Ventilation Symposium, Lexington, KY, June 5-7, 1995.
Greninger, N.B., Weiss, E.S., Luzik, S.J., and Stephan, C.R., 1991, "Evaluation of Solid-Block and
Cementitious Foam Seals", U.S. Department of the Interior, Bureau of Mines, Report of
Investigations 9382.
Hooker, W.K., 1990, "Mined Caverns, Leyden Mine Storage", American Gas Association GEOP
Book S-1, Underground Storage, pp. 77-95.
Joubert, J.I., Grein, CT, and Bienstock, D. 1973. "Sorption of Methane in Moist Coal", Fuel, vol.
52, pp. 181-185.
Kim, A.G., 1977, "Estimating Methane Content of Bituminous Coalbeds from Adsorption Data",
U.S. Department of the Interior, Bureau of Mines, Report of Investigations 8245.
Kissel, F.N., and Bielicki, R.J., 1972, "An In-Situ Diffusion Parameter for the Pittsburgh and
Pocahontas No. 3 Coalbeds", U.S. Department of the Interior, Bureau of Mines, Report of
Investigations 7668.
McPherson, 1993, Subsurface Ventilation and Environmental Engineering. Chapman and Hall, 2-
6 Boundary Row, London, 1993.
47
-------
Nilsen, B. and Olsen B., 1989, Storage of Gases in Rock Caverns. Proceeding of the
International Conference on Storage of Gases in Rock Caverns, Trondheim, June 26-28, 1989,
A.A. Balkema, Rotterdam.
Tek, M.R., 1987, Underground Storage of Natural Gas. Complete Design and Operational
Procedures with Significant Case Histories. Contributions in Petroleum Geology and Engineering,
Volume 3, Gulf Publishing Company, Book Division, Houston, TX.
U.S. DOI, 1993, Mine Map Repositories: A Source of Mine Map Data. U.S. Department of the
Interior, Office of Surface Mining and Enforcement, Program Information Development, April,
1993.
U.S. EPA, 1997, "Identifying Opportunities for Methane Recovery at U.S. Coal Mines: Draft
Profiles of Selected Gassy Underground Coal Mines", U.S. EPA 430-R-97-020, September, 1997.
U.S. EPA, 1998a, "Gas Storage at the Abandoned Leyden Coal Mine near Denver, Colorado",
White Paper, June 1, 1998.
U.S. EPA, 1998b, "Legal Issues Related to Coalbed Methane Storage in Abandoned Coal Mines
in Virginia, West Virginia, Pennsylvania, Utah, Colorado, and Alabama", White Paper, June 20,
1998.
Wall Street Journal, 1997, NYMEX Futures, May 5, 1997.
48
-------
FOR MORE INFORMATION ...
For more information on the technical and economic feasibility of storing CMM in
closed/abandoned underground coal mines, or for information on U.S. EPA Coalbed Methane
Outreach Program and it services, contact:
Roger Fernandez Karl Schultz
Phone (202) 564-9481 (202) 964-9468
Fax (202) 565-2077 (202) 565-2077
e-mail fernandez.roger@epa.gov schultz.karl@epa.gov
49
-------
-------
-------
------- |