ADVANCED RESOURCES INTERNATIONAL, INC. 

4501 Fairfax Dr, Suite 910, Arlington, Virginia 22203 Phone: (703) 528-8420 Fax: (703) 528-0439

Memorandum

To: James Covington; U.S. Environmental Protection Agency 

From: Michael Godec; Advanced Resources International, Inc. 

Date: 11/10/2010 

Re: Review of prospective but non-producing coalbed methane basins 

The purpose of this memo is to describe possible new coalbed methane (CBM) basins with a 

potential for strong development or pilot large scale work, but where current activity is limited. 

The Environmental Protection Agency (EPA) survey of CBM extraction operations is, of course, 

focusing on basins with current CBM development and production operations. EPA will use the 

responses collected in this detailed questionnaire to inform its decision on whether to initiate a 

rulemaking to potentially revise the effluent guidelines for the Oil and Gas Extraction Point 

Source Category (40 CFR 435) to include limits for pollutants discharged in CBM produced 

water. Operators in the following CBM basins are expected to respond to the EPA survey (see 

Figure 1): 

• Alabama/Florida/Mississippi Salt Dome Basin 

• Anadarko Basin 

• Appalachian Basin (Northern and Central) 

• Arkla Basin 

• Arkoma Basin 

• Big Horn Basin 

• Black Warrior Basin 

• Cahaba Basin 

• Cherokee/Forest City Basin 

• Ft. Worth Basin 

• Green River Basin 

• Illinois Basin 

• Permian Basin 

• Powder River Basin 

• Raton Basin 

• Salina Basin 

• San Juan Basin 

• Gulf Coast Tertiary Coal Basin 

• Uinta-Piceance Basin 

• Wind River Basin 
 November 10, 2010 

Figure 1 

U.S. Environmental Protection Agency 

2007 Coalbed Methane Industry Screener 

While much of the higher quality, easier to produce CBM resource plays have been found, and 

are the primary focus of the EPA survey, additional CBM prospects exist in deeper coals and 

lower rank coals, as well as in other areas. Resources in these basins will not be targeted by the 

EPA survey of operators, because, in general, they have not yet undergone much development. 

The primary resources in this category include: 

• Deep coals of the Greater Green River and Piceance Basins 

• Undeveloped CBM plays in Alaska 

• Resources in the Pacific Northwest coal region 

• The Black Mesa Basin in Arizona 

• Low rank coals in the Gulf Coast 

Each of these prospective areas is summarized below. 

1. Green River and Piceance Basin CBM. The coalbed methane in the Green River and 

Piceance basins has long been noted for two things -- the vast in-place resource and their 

considerable depth. Estimates put the in-place coalbed methane resource of the Green River 

Basin at 314 trillion cubic feet (Tcf), and of the Piceance Basin at 84 Tcf. 
 November 10, 2010 

In the Piceance Basin, the Cameo coal (in the “Paludal” zone located below the Williams Fork 

(Mesaverde) tight gas sands) contains about 80% of the basin’s CBM resource. During the 

1980s and early 1990s, producers experimented with commingling production from these deep 

tight gas sands and coals, motivated, in part, by Section 29 tax credits. However, the high 

reservoir pressure and the increase in water production from completing the coals eventually 

discouraged this practice. More recently, EnCana has reported completing the entire Williams 

Fork (Mesaverde) interval, including the lower “Paludal coal zone”, using vertical wells and 

multiple fracs. 

In the Green River Basin, 85% of the 314 Tcf of coalbed methane resource occurs below 6,000 

feet. Since the early 1990s, operators have attempted to tap into these deep coals through 

completions into multiple seams or through commingled completions of coals and overlying 

Mesaverde tight gas sands, all with limited success. Today, drilling for these coals is underway 

in the Atlantic and Pacific Rim projects, along the shallower flanks of the Washakie Basin. 

However, these deeper plays are geographically coincident with the shallower CBM plays under 

development in the Piceance and Unita Basins, so existing operations in these geographic 

areas, while perhaps not in pursuing development in these specific, deeper geologic formations, 

are addressed in the survey. 

2. Undeveloped CBM plays in Alaska. Alaska has major CBM resources estimated at 776 Tcf 

of gas in place, slightly larger than the CBM resource base in the entire Lower-48 states. None 

of Alaska’s CBM potential has been commercially developed, due to its remoteness from 

markets, and (until perhaps recently) insufficient natural gas prices for economic viability. Most 

of the CBM resource (621 Tcf) is located in bituminous-rank coals of the North Slope region. 

Prospective but still untested, the North Slope CBM resources lack markets and development 

must await construction of natural gas pipeline from the Alaska North Slope to viable markets. 

However, CBM resources in the onshore Cook Inlet region in southern Alaska (136 Tcf) are 

more conveniently located, close to the Kenai liquefied natural gas (LNG) facility, and thus have 

brighter market prospects. Reservoir characteristics appear favorable (thick, sub-bituminous 

coal with 100-200 standard cubic feet per ton (scf/ton) gas content). The Pioneer/Evergreen 

pilot -- though not commercially successful (gas prices were $1.80/Mcf at the time) – is the only 

CBM test and provided useful data. Cook Inlet CBM could replace dwindling conventional gas 

supplies for Kenai at attractive prices (~$6 to 9/Mcf). Recent efforts in Australia to develop CBM 

for LNG exports have sparked renewed interest in Cook Inlet’s CBM potential. 

A more detailed characterization of the undeveloped CBM plays in Alaska is provided in 

Appendix A. 

3. Pacific Northwest Coal Region, Washington and Oregon. The structurally complex Pacific 

Northwest Coal Region (PNCR) in Washington and Oregon contains significant (~10 Tcf) 

undeveloped coalbed methane resources in place. CBM testing since 1987 by Texaco, El 

Paso, and smaller operators has not been commercially successful but did measure 

encouraging gas content (up to 500 scf/ton), permeability (up to 300 millidarcies (md)), and 

short-term gas flow rates up to 500,000 cubic feet per day (Mcfd). Produced water in some 

pilots was fresh, enabling surface discharge under state permits.

The main challenges in the PNCR have been relatively complex structural conditions, including 

faulting, steep dips, and unstable coals. In addition, vertical well fracturing and completion have 

not been effective to date. Horizontal drilling has not yet been attempted. Geologically, PNCR 

is one of the most challenging undeveloped CBM areas in the US, though the lack of 

conventional gas production in the region is a positive market factor. Higher gas prices likely 
 November 10, 2010 

would stimulate further exploration in this region, perhaps introducing advanced horizontal 

drilling. 

A more detailed characterization of the undeveloped CBM plays in Pacific Northwest Coal 

Region is provided in Appendix B. 

4. Black Mesa Basin, Arizona. The 2,500 square mile Black Mesa Basin in northeastern 

Arizona contains extensive coal resources that have not been tested for CBM but could have 

significant potential (1-10 Tcf). The northern part of the basin has experienced large-scale 

surface coal mining since the 1960s, but conflicting ownership claims on Hopi and Navajo lands 

further south in the basin have discouraged CBM testing to date. Black Mesa is perhaps the 

last significant untested CBM basin in the US Rocky Mountain region. 

Based on outcrop studies and data from sparse oil and gas wells drilled in the 1950s through 

the 1970s, CBM reservoir conditions in Black Mesa appear prospective and might even 

approach those of the commercially developed San Juan and Raton Basins nearby. In certain 

respects, Black Mesa resembles the undeveloped Raton basin of 20 years ago (though it is 

50% larger than the Raton). Cretaceous Wepo Formation coals total up to 60 feet thick and dip 

south from outcrop to a depth of approximately 3,000 feet in the basin’s center. Coal rank 

ranges from sub-bituminous to high-volatile bituminous A. Thinner coals occur in the underlying 

Cretaceous Toreva and Dakota Formations. Market access could be via the recently 

constructed Questar Southern Trails gas pipeline, which crosses the northern edge of the basin, 

or the El Paso Lincoln pipeline, which crosses just south of the basin. 

A more detailed characterization of the undeveloped CBM plays in the Black Mesa Basin is 

provided in Appendix C. 

5. Low Rank Coals in the Gulf Coast A large in-place coalbed methane resource exists in Gulf 

work by the U.S. Geological Survey (USGS) estimates total undiscovered technically 

recoverable resources in the Cretaceous-Tertiary Coal beds of the Gulf Coast Region to range 

from 1.7 to 7.9 Tcf, with a mean estimate of 4.1 Tcf.1 Prospective coals occur at depths of 

1,500 to 5,000 foot depths with more mature, gas rich coals existing below 3,000 feet. Drilling 

has been limited to individual test pilots and significant production has yet to be established. 

However, leasing has been active, with over 400,000 acres leased to date. 

A more detailed characterization of the undeveloped CBM plays in the Black Mesa Basin is 

provided in Appendix D. 

6. Other Low Rank Coals in the U.S. Conventional wisdom assumes that lignite is of too low a 

grade to be a commercially viable source of methane. However, ongoing activities in the Texas 

Gulf Coast are challenging this assumption. A number of other areas in the U.S. have low rank 

coals. In addition to the Gulf Coast and Alaska, low rank coals exist throughout much of the 

west, including North Dakota, Northern Montana, and Michigan. Little work has been done to 

assess the coalbed methane potential of these coals, and development activity regarding this 

resource is minimal. 

Nonetheless, there is some anecdotal evidence from ranchers and water well drillers, for 

example, suggesting that coalbed methane may indeed occur in some of the lignites of North 

Dakota. The occurrence of coalbed methane appears to be related to the thickness of a coal 

seam, the thickness of the overburden, and the hydrostatic pressure of water within the seam. 

Detailed knowledge of the nature of target coals is critical to the evaluation of its potential as a 

coalbed methane resource. 
 November 10, 2010 

Appendix A 

Preliminary Evaluation of Alaska’s Undeveloped CBM Resource 

Potential 

1. Summary 

Alaska has major CBM resources estimated at 776 Tcf of gas in place, slightly larger than the 

CBM resource base in the Lower-48 states. None of Alaska’s CBM potential has been 

commercially developed, due to its remoteness from markets and (until recently) low gas prices. 

Most of the CBM resource (621 Tcf) is located in bituminous-rank coals of the North Slope 

region. Prospective but still untested, the North Slope CBM resources lack markets and 

development must await construction of the planned North Slope gas pipeline. 

However, CBM resources in the onshore Cook Inlet region in southern Alaska (136 Tcf) are 

more conveniently located close to the Kenai LNG facility and thus have brighter market 

prospects. Reservoir characteristics appear favorable (thick, sub-bituminous coal with 100-200 

scf/ton gas content). The Pioneer/Evergreen pilot -- though not commercially successful (gas 

prices were $1.80/Mcf at the time) – is the only CBM test and provided useful data. Cook Inlet 

CBM could replace dwindling conventional gas supplies for Kenai at attractive prices (~$6-

9/Mcf). The Australian CBM-to-LNG paradigm has sparked renewed interest in Cook Inlet’s 

CBM potential. 

2. Resource Potential 

Though mining has been limited, Alaska contains major coal deposits that range from shallow 

outcrop to over 2,000 meters deep. Three major geologic provinces account for nearly 90% of 

Alaska’s coal resources: 1) Northern Alaska - North Slope Region; 2) Central Alaska – Nenana 

Region; and 3) Southern Alaska – Cook Inlet Region. 

CBM Resources in Alaska were initially estimated by the Alaska DNR to be around 1,000 Tcf of 

gas in place, including 245 Tcf in the Cook Inlet. 2 In 2004, the USGS coal resource evaluation 

examined CBM in Alaska, characterizing it as “exceedingly large,” but did not actually quantify 

CBM resources. 3 In 2006 the USGS assessed North Slope CBM resources, estimating a total 

of 19 Tcf in place,4 which would imply an average gas content of only 6 scf/ton. This seems 

“exceedingly low,” much lower than the 100-200 scf/ton tested in the Cook Inlet basin. 

Advanced Resources has recently developed an independent, preliminary estimate of Alaska 

CBM resources (Table A-1). Gas content was assumed to range from 100 scf/ton in the 

relatively low-rank and shallow Nenana region, to 150 scf/ton in the deeper but still subbituminous Cook Inlet area, to 200 scf/ton in the higher-rank and deeper North Slope region. 

Using this methodology, we estimate CBM resources in Alaska to be approximately 758 Tcf. 

Onshore Cook Inlet has about 136 Tcf of accessible CBM resources in place, similar to a 

published estimate (using similar methodology) of 140 Tcf.5 

North Slope. The North Slope region has coals in the Lower Cretaceous Nanushuk and Upper 

Cretaceous Colville Groups as well as in the Tertiary Sagavanirktok Group. Coal underlies an 

area of approximately 83,000 km2. Coal rank ranges from lignite A to high-volatile A bituminous, 

with a mean rank of high-volatile C bituminous. Identified resources are 120 billion short tons, 

with a further 3,870 billion tons of undiscovered but likely coal resources. ARI estimates there 

are approximately 621 Tcf of coalbed methane resources in the North Slope. However, these 

resources are located far from gas markets, have never been tested, and thus remain poorly 

characterized. 

Central Alaska. The Central Alaska – Nenana region has Tertiary coals estimated at 6.4 to 7.7 

billion tons of identified resources, with an additional 10 billion tons of undiscovered resources.6 
 November 10, 2010 

The region is not continuously underlain by coal, but instead comprises numerous small 

structural basins (synclines) that are separated by anticlinal highs. Coal occurs in the Tertiary 

Usibelli Group. Coal thickness is approximately 50 to 66 feet and occurs at depths ranging from 

surface to around 3,000 feet. Coal rank ranges from lignite to sub-bituminous, mainly subbituminous C. Although smaller than the North Slope and Cook Inlet, the Nenana basin is the 

only coal province in Alaska that is currently being mined. ARI estimates CBM resources in 

Central Alaska at about 1 Tcf. 

Cook Inlet. The Cook Inlet region has the most prospective CBM resources in the state. Major 

coal deposits occur in the Miocene Tyonek Formation. Demonstrated coal resources are 

estimated at 2.9 to 12 billion tons, with another 970 to 1,600 billion tons of undiscovered 

resources. The coals can total up to 1,000 feet or more in places. They often occur at optimal 

depths of 1,000 to 4,000 feet. Coal rank is sub-bituminous to high-volatile bituminous C. These 

coals sourced most of Cook Inlet’s conventional natural gas reserves. 

CBM Testing. To date, the only Alaska CBM area to experience significant well testing has 

been the onshore Cook Inlet. Projects have included a state DNR gas content core hole and 

Pioneer’s 4-well production pilot. 

• Alaska DNR. In 1994 the Alaska Department of Natural Resources drilled Alaska’s first gas 

content core hole about 50 km northeast of Anchorage. Approximately 40 feet of coal was 

cored and desorbed. Gas content was encouragingly high and increased regularly with 

depth, from 63 scf/ton (d.a.f.) at 500-foot depth (Ro=0.47%), to 245 scf/ton at a depth of 

1,300 feet (Ro=0.58%). Gas composition was mainly methane (98-99%), with minor CO2

and N2. 

• Evergreen. During 2002-2004, Evergreen Resources (now Pioneer) tested a 300,000-acre 

lease. Oligocene-Miocene Tyonek Formation coals total 80-150 ft thick, are high-volatile 

bituminous in rank (Ro=0.6%), and occur at depths of 2,600 to 3,700 feet. Evergreen drilled 

two separate 4-well CBM pilot production patterns (total 8 vertical ells) and hydraulically 

stimulated all four wells of the first pilot and one well of the second pilot. Drilling permits 

were granted for two water-disposal wells. However, Evergreen abandoned the project in 

2004 following long-term production testing, saying it was “probably not capable of 

commercial production.” Note that the $1.80/Mcf wellhead gas price was among the lowest 

in the USA at the time. 

3. Market Potential. While much of Alaska’s CBM potential is remote from existing pipeline 

and gas market infrastructure, several potential marketing opportunities have emerged in recent 

years: 

• Anchorage. The city of Anchorage is served by conventional natural gas fields that are in 

long-term decline. Pioneer Resources’ initial CBM pilot in the onshore Cook Inlet basin was 

intended to serve the Anchorage market initially. The local utility Enstar paid an average 

$8.75/Mcf for natural gas supplies in 2008, up from $1.80/Mcf ten years ago. 

• Kenai LNG. A much larger and longer-term potential market for Alaska CBM would be to 

develop the vast resources present in the Cook Inlet region to replace rapidly declining 

conventional gas supplies for the Kenai LNG facility. Already, concerned Japanese LNG 

companies have begun to look into Cook Inlet’s CBM potential as they seek reliable supplies 

for future decades from this key facility. And given the new Australian paradigm of 

developing CBM for LNG, industry has taken renewed interest in Cook Inlet’s CBM 

resources. 

Operated by ConocoPhillips (70%) and Marathon (30%), the Kenai-Nikiski plant has annual 

production of about 1.2 million tons. Most of Kenai’s production is exported to Japan. Kenai 
 November 10, 2010 

is the oldest LNG plant, having started production in 1969. Current estimates of the 

conventional gas reserves remaining in the Cook Inlet Basin vary from 1 to 2 Tcf, insufficient 

for long-term LNG exports. Furthermore, the conventional gas produced for Kenai requires 

compression, placing CBM resources on a more equal footing. 

• Alaska Gas Pipeline. In the more distant future, there is likely to be a natural gas pipeline 

constructed to transport stranded conventional gas reserves in the North Slope to southern 

markets. If cost-competitive, the North Slope CBM resources could be developed and 

marketed via this planned pipeline. ExxonMobil and TransCanada recently announced a 

joint-venture to bid on the pipeline project. 

Figure A-1: Coal Basins and CBM Resources In Alaska
 November 10, 2010 

Table A-1: CBM Resources in Alaska 

Identified & Identified & HighUndiscovered Mean Mean Undiscovered Mean Total Graded

Coal Ash Moisture Coal Volatile Methane CBM CBM

Resources Content Content Resources Matter Content Resources Resources

Region (Btons) (%) (%) (Btons, daf) (%) (scf/ton, daf) (Tcf) (Tcf)

North Slope 4,020 10.3 12.5 3,103 30.1 USGS 6 18

North Slope 4,020 10.3 12.5 3,103 30.1 ARI 200 621

Nenana 17 9.9 24.7 11 35.9 ARI 100 1

Cook Inlet 1,292 10.0 20.0 905 35.0 ARI 150 136 27.1

ARI Total 5,329 4,019 ARI 758
 November 10, 2010 

Appendix B 

Pacific Northwest Coal Region, Washington and Oregon 

1. Summary 

The structurally complex Pacific Northwest Coal Region (PNCR) in Washington and Oregon 

contains significant (~10 Tcf) undeveloped coalbed methane resources in place. CBM testing 

since 1987 by Texaco, El Paso, and smaller operators has not been commercially successful 

but did measure encouraging gas content (up to 500 scf/ton), permeability (up to 300 md), and 

short-term gas flow rates (up to 500 Mcfd). Produced water in some pilots was fresh, enabling 

surface discharge under state permits. 

The main challenges in the PNCR have been relatively complex structural conditions, including 

faulting, steep dips, and unstable coals. In addition, vertical well fracturing and completion have 

not been effective to date. Horizontal drilling has not yet been attempted. Geologically, PNCR 

is one of the most challenging undeveloped CBM areas in the USA, though the lack of 

conventional gas production in the region is a positive market factor. Higher gas prices likely 

would stimulate further exploration in this region, perhaps introducing advanced horizontal 

drilling. 

2. Resource Potential 

The Pacific Northwest Coal Region (PNCR) comprises a series of discrete fault-bounded coal 

fields that stretch from southwestern Oregon, through central Washington, and into western 

British Columbia (Figure B-1). CBM resources in this region have not been rigorously 

assessed, although early scoping-level estimates have ranged from 0.3 to 24 Tcf.7,8,9

Eocene-age coal-bearing formations include the Cowlitz, Skookumchuck, Carbonado, Spiketon, 

Tiger Mountain, and Renton Formations, as well as the undivided Puget Group (Figure B-2). 

These units were deposited in a variety of deltaic, fluvial, brackish, and shallow-marine 

environments. Coal rank is mainly bituminous, with some sub-bituminous coals. Gas contents 

are fairly high, up to 500 scf/ton. Although not ideal due to their structural complexity, CBM 

deposits in the PNCR do benefit from a lack of conventional gas production in the region. 

3. Exploration Testing 

The Pacific Northwest underwent an initial phase of CBM exploration activity took place during 

1982-93, including the Amoco, Texaco, and Carbon River Energy pilots. Early wells qualified 

for Section 29 non-conventional gas tax credits, which expired at the end of 1992. However, the 

initial projects were unsuccessful due to structural complexity, faulting, steep dips, and poor well 

completion practices, as well as relatively low prevailing wellhead gas prices (~$2/Mcf). 

Texaco, Palo Petroleum, and Boeing teamed up in 1992 to drill three wells near Black 

Diamond, WA. One well was hydraulically fractured with nitrogen foam and sand, while the 

other two wells were completed by open-hole cavitation. The best well tested 30-200 Mcfd from 

Eocene coal seams at depths of 2,500-3,300 feet. However, steep dips in this area led to 

severe borehole deviation during drilling, and caused hole collapse during the cavitation 

operations. Although these wells penetrated over 30 meters of coal, production results were 

disappointing. 

A second CBM testing phase started about 2000, stimulated by higher gas prices (>$5/Mcf), 

new exploration concepts, and improved well completion technology. These more recent 

projects, though still not economically successful, have tested encouraging levels of coal seam 
 November 10, 2010 

gas content and permeability in the region. Recent operators have included El Paso 

Corporation, Duncan Oil, Torrent Energy, and Comet Ridge Ltd. 

Partners El Paso Corp. and Duncan Oil tested the Northwest’s largest CBM pilot.10 The 

Carbonado CBM project covered 264,014 acres in King and Pearce Counties located 30 miles 

SE of Tacoma. A total of 14 CBM production wells and 4 core holes were drilled, targeting 

more than two dozen coal seams in the Puget Group totaling nearly 80 feet thick at depths of 

approximately 3,000 feet. Individual coal beds were thin (3 feet) with high ash content (average 

60%), usually separated by 150 feet of sandstone and shale. Intrusive dikes and sills occur 

sporadically. Coal rank was high-medium volatile bituminous. Gas content varied with depth 

and location, with highest values in the southern part of the prospect. Using a minimum 2,000-

foot depth cutoff, the average in-situ gas content was reported to be about 500 scf/ton. 

All 14 production wells were hydraulically stimulated, using a variety of fluids. Eight of the wells 

used nitrogen foam with 90 tons of sand proppant per zone. Four wells were used slickwater 

KCl fluid, with about 23 tons of sand per zone. Two of the wells utilized polymer fluid with 42 

tons of sand proppant per zone. El Paso did not release detailed production data. Some wells 

reportedly produced at high water rates, sometimes exceeding the 1000 barrels per day 

installed pump capacity. Based on injection/falloff testing and production analysis, the company 

estimated coal seam permeability to range from 1 to 300 md, with a regional average 1 to 7 md. 

(This is lower permeability than found in the San Juan and Powder River basins, but similar to 

the levels encountered in the Warrior basin of Alabama.) 

Produced water at El Paso’s pilot was quite fresh and disposed by surface discharge into local 

streams under permit from the State of Washington, although capacity constraints required 

some of the water to be trucked to a local water utility. Despite operating in what some consider 

to be an environmentally restrictive part of the country, El Paso had no issues obtaining drilling 

permits, mainly because the locations were situated on private timberlands that were scheduled 

for clear cutting. Had the project proceeded, access to Northwest Pipeline’s trunk line would 

have required construction of a 10-mile connecting pipeline. El Paso eventually abandoned the 

project due to high water and low gas production. 

Comet Ridge Limited (based in Sydney, Australia) currently is conducting a CBM and 

conventional gas exploration program in the Grays Harbor area southwest of Seattle.11 Comet 

Ridge’s subsidiary St. Helens Energy LLC holds mineral rights to 50,000 acres and has a lease 

option for an additional 420,000 acres at low bonus costs (<$0.50/acre). The company has 

completed a 3-D seismic survey in the block and is nearing completion of a 2-D seismic shoot. 

After processing and interpreting the seismic data, Comet Ridge plans its first test well later 

during 2009. 

Torrent Energy (based in Coos Bay Basin, Oregon) conducted extensive CBM testing at its 

Coos Bay block further south in southwestern Oregon.12 The Coos Bay basin is the 

southernmost of a series of coal-bearing Tertiary sedimentary basins (the Puget-Willamette 

Trough) that stretch from southern Oregon to northern Washington. Coal seams occur in the 

Lower and Upper Members of the Middle Eocene Coaledo Formation. Net coal thickness totals 

up to 60 feet and 30 feet, respectively, in the Lower and Upper Coaledo units. The coal rank 

ranges from sub-bituminous to high-volatile bituminous. Approximately 20 conventional oil and 

gas exploration wells were drilled in the Coos Bay basin between 1914 and 1993, many of 

which encountered gas kicks in the coal seams penetrated during drilling. An independent 

engineering study estimated total gas in place on Torrent’s acreage at approximately 1.2 Tcf. 

Torrent commenced an initial multi-hole CBM coring program at Coos Bay in October 2004. 

The company drilled and tested a total of 12 exploration wells in three pilot areas: Beaver Hill (5 

wells), Radio Hill (2), and Westport (5). In May 2008, Torrent completed initial fracture 
 November 10, 2010 

stimulation of 5 CBM wells at Beaver Hill and started production testing. Torrent claims the coal 

seams were saturated with pipeline-quality natural gas, but the project did not book proved 

reserves and has been placed on hold due to the company’s financial difficulties. 

Core samples from 11 coal seams at the three test sites were desorbed at the well site. Based 

on initial results, the Beaver Hill core hole site was selected for a 5-well production pilot. Its 

original core hole was cased and converted to a production well. Four new wells were 

directionally drilled around it in a pattern from the same drilling location. All five wells 

penetrated multiple Lower Coaledo coal seams at depths of about 4,000 feet. The 5-m thick “D” 

seam in each well was stimulated with a nitrogen frac. Short-term rates of 200-500 Mcfd were 

reported. 

Torrent tested one well at its Radio Hill site, completing 10 Lower Coaledo coal seams at depths 

of 2500-3000 feet and with a cumulative net coal thickness of 33 feet. The coals were 

stimulated with nitrogen fracs. Reported gas rate was much lower than at the Beaver Hill pilot, 

about 30 Mcfd with about 6 bwpd. 

Produced water chemistry was not reported but appears too saline for surface discharge. The 

produced water from the Torrent pilots was trucked to a dilution facility adjacent to the municipal 

water-treatment plant at Coos Bay. Torrent had planned to evaluate fractured basalts beneath 

the Coaledo Formation at its Westport project site as a possible injection zone for produced 

water. The Oregon Department of Environmental Quality would require an approved water 

disposal/containment plan for any commercial-scale CBM production; they have ruled out 

surface discharge. 
 November 10, 2010 

Figure B-1: CBM Deposits and Testing, Pacific Northwest Coal Region 
 November 10, 2010 

Figure B-2: Coal and CBM Stratigraphy, Pacific Northwest Coal Region 
 November 10, 2010 

Appendix C 

Black Mesa Basin, Arizona 

1. Summary 

The 2,500 square mile Black Mesa Basin in northeastern Arizona contains extensive coal 

resources that have not been tested for CBM but could have significant potential (1-10 Tcf).13 

The northern part of the basin has experienced large-scale surface coal mining since the 1960s, 

but conflicting ownership claims on Hopi and Navajo lands further south in the basin have 

discouraged CBM testing to date. Black Mesa is perhaps the last significant untested CBM 

basin in the US Rocky Mountain region. 

Based on outcrop studies and data from sparse oil and gas wells drilled in the 1950s through 

the 1970s, CBM reservoir conditions in Black Mesa appear prospective and might even 

approach those of the commercially developed San Juan and Raton Basins nearby. In certain 

respects, Black Mesa resembles the undeveloped Raton basin of 20 years ago (though it is 

50% larger than the Raton). Cretaceous Wepo Formation coals total up to 60 feet thick and dip 

south from outcrop to a depth of approximately 3,000 feet in the basin’s center. Coal rank 

ranges from sub-bituminous to high-volatile bituminous A. Thinner coals occur in the underlying 

Cretaceous Toreva and Dakota Formations. Market access could be via the recently 

constructed Questar Southern Trails gas pipeline, which crosses the northern edge of the basin, 

or the El Paso Lincoln pipeline, which crosses just south of the basin. 

2. Resource Potential 

The Cretaceous Mesaverde Group offers three potential CBM targets (Figure C-1). The 

thickest is the Wepo Formation, with up to 60 feet of coal, while the underlying Toreva and 

Dakota formations contain an additional 10 to 50 feet.

14 Wepo coals are high-volatile 

bituminous (12,400 Btu/lb; dry basis). Toreva and Dakota coals are lower in rank at outcrop, but 

may increase to bituminous levels below 2,000-foot depths. Structure is favorably simple, with 

gently dipping strata interrupted by broad Laramide-age folds that were formed over Laramide 

or reactivated Precambrian basement faults. 

CBM development in the Black Mesa Basin faces several challenges. The thickest coals are 

mapped in the northern shallow part of the basin, where gas content is low (Figure C-2). 

Deeper areas (2,000 to 3,000 feet) in the center of the basin have better CBM potential but are 

mapped as having thin coal. However, this may be more due to lack of reliable log data than 

actual coal thickness trends. Erosion has cut deep canyons across the recently uplifted basin, 

locally exposing and possibly degassing the Wepo and Toreva coals. However, the lowermost 

Dakota coals are not exposed and, as in the Raton Basin, the Black Mesa has extensive 

uneroded plateaus where coals remain buried and may be gas saturated. 

3. Market Potential. Black Mesa has never been a gas-productive basin, thus there is no gas 

pipeline infrastructure within the basin’s interior. However, the perimeter of the basin is served 

by two interstate gas pipelines that transport gas from the San Juan basin to southern California 

markets. Questar’s 16-inch diameter, 80-MMcfd capacity Southern Trails gas pipeline, 

converted from an existing disused oil pipeline in 2002, crosses the northwestern edge of the 

Black Mesa basin. El Paso’s Lincoln pipeline crosses just south of the basin and has 600 

MMcfd capacity. 
 November 10, 2010 

Figure C-1: Coal and CBM Stratigraphy, Black Mesa Basin 

Primary CBM Target

Secondary

CBM Targets

Modified from 

Nations, 2002
 November 10, 2010 

Figure C-2: Coal Thickness Distribution Map, Black Mesa Basin 

Modified from Nations, 2002
 November 10, 2010 

Appendix D 

Coalbed Methane Potential of Low Rank Coals in the Gulf Coast 

1. Summary 

A large in-place coalbed methane resource exists in Gulf Coast Tertiary coals, stretching from 

the Florida panhandle to the Texas Gulf Coast, Figure 1. Recent work by the U.S. Geological 

Survey (USGS) estimates total undiscovered technically recoverable resources in the 

Cretaceous-Tertiary Coal beds of the Gulf Coast Region to range from 1.7 to 7.9 Tcf, with a 

mean estimate of 4.1 Tcf.15 Prospective coals occur at depths of 1,500 to 5,000 foot depths 

with more mature, gas rich coals existing below 3,000 feet. Drilling has been limited to 

individual test pilots and significant production has yet to be established. However, leasing has 

been active, with over 400,000 acres leased to date. 

Figure 1. Gulf Coast Tertiary Coal Belt (Louisiana to Florida) 

1,000

5,000

10,000

2,000

10,000

0 70 140 210 280 Miles

N

Legend

Wilcox Depth Contour ft

1000

2000

5000

10000

States

Source: based on data from http://pubs.usgs.gov/of/2000/ofr-00-0113/wlcxmaps.htm#1 JO
 November 10, 2010 

2. Resource Potential 

Recent investigations suggest that significant coalbed gas resources may exist in the lower 

Trinity Group and Hosston Formation (both Lower Cretaceous), Midway Group (Paleocene), 

and Wilcox Group (Paleocene-Eocene) of the Gulf of Mexico Coastal Plain. At outcrop, these 

coals are generally classified as lignites. However, thermal maturity increases with depth in 

these formations, and although comprehensive data are lacking, coal rank is most likely 

subbituminous at depth. Drill records from Arkansas and Louisiana indicate that there are 

Cretaceous coal beds greater than 10 feet thick at depths of 1,500- 6,000 feet suitable for 

coalbed gas development. Available data from conventional oil and gas wells in Louisiana 

indicate that upper, middle, and lower Wilcox Group coal zones have potential for coalbed gas 

accumulations and similar data from Texas, Arkansas, Mississippi, and Alabama indicate that 

gas may be present in coal beds of the lower and middle sections of the Wilcox. In addition, gas 

accumulations may occur in the coal beds of the upper part of the Midway Group in Mississippi 

and Alabama. 

Public data from several wells completed in Wilcox Group coal zones in north-central Louisiana 

indicate that initial production ranges from 7 to 122 thousand cubic feet (Mcf) of gas per day. In 

Louisiana, the depth to the targeted Wilcox coal beds ranges from 1,500 to 5,000 feet, and 

individual coal beds have a maximum thickness of about 20 feet. The thickest coal beds tend to 

be in the lower Wilcox coal zone and cumulative coal thickness can exceed 100 feet. 

Much of the early work characterizing the coalbed methane resource in Louisiana was done by 

John Echols, then with the Louisiana Geological Survey.16, The U.S. Geological Survey (USGS) 

also has looked into the resource potential of Gulf Coast coal seams.17

More data are needed to better characterize and assess the coalbed gas potential for the 

Cretaceous coal beds in this region. Regional studies by the Louisiana Geological Survey and 

the Texas Bureau of Economic Geology are ongoing to better determine the extent and 

characteristics of coalbed methane resources in the Gulf Coast. 

Nonetheless, the USGS recently completed an assessment of the undiscovered continuous gas 

potential of Cretaceous-Tertiary coal beds of the onshore areas and State waters of the Gulf 

Coast. They estimate that total undiscovered technically recoverable resources in the Gulf 

Coast Region to range from 1.7 to 7.9 Tcf, with a mean estimate of 4.06 Tcf in the geologic 

provinces they assessed. Nearly all of the undiscovered gas resource is assessed within the 

Wilcox Coalbed Gas assessment unit. .The unconventional gas resources were estimated to 

reside in coalbed reservoirs and in adjacent and interfingered sandstones deposited in fluvial 

and deltaic depositional environments. The assessment results reflect estimates based on 

vertical drilling technology. 

Similarly, the Potential Gas Committee, in their 2006 assessment, estimated that undiscovered 

(speculative) coalbed methane resources in their Gulf Coast region ranged from 1.5 to 6.75 Tcf, 

with a most likely estimate of 3.4 Tcf.18

3. Development History 

Louisiana

Devon Energy Co. drilled the first pilot program in Caldwell Parish, where Devon and Donner 

Properties share a common interest in the minerals over a large area. The first coalbed well was 

drilled in Caldwell Parish in 1989, but was plugged and abandoned in the same year.19

Nonetheless, this test proved that the so-called lignite was actually subbituminous, with good 

gas content, at the depths targeted. 
 November 10, 2010 

After John Echols left Louisiana State University Basin Research Institute for private industry, 

he also drilled a test in Caldwell Parish. King Drilling drilled a coal seam well in LaSalle Parish. 

Other players include GeoMet, Inc., Mark V Petroleum Co., Harvest Gas Management, Vintage 

Petroleum Inc., EnerVest Operating Co., Samson Resources and other companies are 

acquiring leases. Southwestern Energy Co. had the most producing wells, 29, as of the first of 

May 2008. Most of these companies are keeping what they know to themselves. 20

In Louisiana, exploration is underway in the north central portion of the state; in particular 

Caldwell and LaSalle parishes and those surrounding them. Sixteen CBM wells were drilled in 

2006, and 26 wells have been spudded in 2007 as of October 1. As of August, 2008, there were 

44 producing wells that have produced from 10 to 250 Mcf per day, according to some sources 

and 9 in various stages of dewatering. The companies drilling the wells have not divulged much 

information about the production or drilling details publicly.21

Prior to 2005, Louisiana did not have law appropriate for coalbed methane wells. Government 

and industry worked together to successfully educate the legislature regarding the need for 

larger units and state regulations were changed. The horizontal wells these plays demand are 

expensive, but can effectively cover large areas, so up to 5,000 acre units were created to 

maximize the potential of each location. 

Texas

The most advanced exploration for coalbed methane in Texas is in the bituminous coals of the 

Olmos Formation in Maverick County, where two companies have leased more than 250,000 

acres and permitted more than 60 wells. These companies have drilled and/or recompleted 

more than 30 wells, which they are testing. One company began limited commercial gas 

production from Olmos coals in early 2001, but early production rates are low and have not yet 

established commerciality of the project. Reportedly, operators are evaluating Wilcox coalbed 

methane in Zavala County, South Texas, and in East-Central Texas. Operators have not 

reported results or commercial gas production.22

4. Market Potential 

The major coal seams of interest in the Gulf Coast are at depths of 2,800 to 3,400 feet, so the 

average cost to drill and complete a well is only about $250,000 to $300,000 per well and early 

test data has established the gas content in the coals as economical. This could make the 

development of Gulf Coast coalbed methane economically competitive with other supplies 

producing in this region, which is served by a plethora of natural gas pipelines. 
 November 10, 2010 

References 

 

1

 U.S. Geological Survey, Assessment of Undiscovered Oil and Gas Resources in Cretaceous-Tertiary 

Coal Beds of the Gulf Coast Region, Fact Sheet 2007-3039, 2007 

2

 Smith, T.N., 1995. “Coalbed Methane Potential for Alaska and Drilling Results for the Upper Cook Inlet.” 

Intergas Conference, May 15-19, Tuscaloosa, Alabama, p. 1-21. 

3

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4

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5

 Montgomery, S.L. and Barker, C.E., “Coalbed Methane, Cook Inlet, South-Central Alaska: A Potential 

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6

 Tyler, R., Scott, A., and Clough, J., 1998. “Coalbed Methane Potential and Exploration Targets for Rural 

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7

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Resources of the United States, AAPG Studies in Geology, Series 17, p. 353-372. 

8

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9

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10 McHenry, J., Bazinski, P., and Lentz, R. “Another Chance for CBM in Mt. Rainier Coal Fields, 

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11 Comet Ridge Limited. Presentation to CSG Summit, Christchurch, New Zealand, June 30, 2009. 

12 Torrent Energy Corporation. Press Releases, January 17, March 20, and May 8, 2007. 

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An Overlooked Rocky Mountain Coalbed Methane Play.” American Association of Petroleum 

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14 Nations, J.D., Swift, R.L., and Haven, H.W., Jr., 2002. “Summary of Cretaceous Stratigraphy and Coal 

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15 U.S. Geological Survey, Assessment of Undiscovered Oil and Gas Resources in Cretaceous-Tertiary 

Coal Beds of the Gulf Coast Region, Fact Sheet 2007-3039, 2007 

16 John B. Echols, “Coalbed Methane: Louisiana's Underexploited Energy Resource,” Basin Research 

Institute Bulletin, a publication of the Louisiana Geological Survey, Volume 9, pages 18-27 (June, 

2000) (www.lgs.lsu.edu) 

17 Breland, F.C., Jr., 2004, Coalbed methane potential in Louisiana, in Warwick, P.D., ed., Selected 

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2004-1273, p. 27-35. 

18 Potential Gas Committee, Potential Supply of Natural Gas in the United States, Report of the Potential 

Gas Committee (December 31, 2006), November 2007 

19 Durham, Louise S., “From the ‘Seam”, Not the “Bed”: Coal Gas Tapped in Louisiana,” AAPG Explorer, 

May 2006 

20 Chance, Diana L., “Louisiana CBM on the Cusp?” Oil and Gas Investor, Special Report on Shale and 

Coalbed Methane, January 2008 

21 McGee, David, “Haynesville Shale Gas Play and Louisiana Coal Seam Natural Gas,” Louisiana 

Department of Natural Resources, Technology Assessment Division, August 2008 

22 Garduno, Jorge Luis, et al., “CO2 Sequestration Potential in Texas Low Rank Coals, SPE Paper No. 

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2003