Coalbed Methane – CH4 Potential of Major U.S. Coal Basins
The potential of producing methane from coals in the United States has been evaluated for about the last 20 years. Although the estimate of recoverable and in-place gas in shallow coals is an approximation, it is anticipated that about 145 Tcf of methane are recoverable from the major coal basins of the contiguous 48 states, according to the 1990 Potential Gas Committee. This estimate represented a rise of 60% over the previous 2 years. However, the recoverable coalbed methane (CBM) reserve was estimated to be 90 Tcf in the year 2000 out of a possible 750 Tcf of coalbed methane (CBM) gas in place.
This recoverable reserve number could change with the recent success in the Piceance basin of Colorado and the Atlantic rim of the Washakie basin in Wyoming. It seems apparent that the reserve estimates will be low if technology improves to allow production of CH4 from the deeper coals and to allow production from marginally economical wells. Although commercial coalbed methane (CBM) production has been confined to the United States and a few other countries, at least 4,000 Tcf of methane exists in coals of the 10 major coal-bearing countries listed in Table 1.2.9 Here, the estimate has even more error.
Fig. 1.9 depicts the locations, relative sizes, and coalbed methane (CBM) potentials of the major U.S. coal basins. The eastern coals in Appalachia and the coals along the Rocky Mountains contain most of the in-place gas. In general, the older coals of the east have attained a higher rank with less ash, and the coals of the west are contained in thicker seams. An extensive infrastructure of pipelines and oilfield services exists for the eastern coal region but not for the western coalfields.
Each of the basins has unique conditions determining the economics of methane production: depth of the coal, gas content, thickness of seams, permeability, access to pipelines, coal mining history in region, presence of logs from conventional gas wells, volume and quality of waters in the seams, and water-disposal limitations. Therefore, important characteristics of each of the 14 basins will be summarized in the following sections of this chapter.
Discontinuous seams, different nomenclature of investigators, and changes in seam designations across state boundaries often cause confusion in tabulations of a basin’s contents. It is probable that any coal basin around the world having prospective commercial coalbed methane (CBM) would be similar to one of these examples.
Fig. 1.9—Major U.S. coal basins.
1.7.1 San Juan Basin
The San Juan basin extends 100 miles wide and 140 miles long over southwestern Colorado and northwestern New Mexico, covering mountainous terrain of public property and tribal reservations. One of its most noteworthy features, however, is that it has the most profitable and prolific coalbed methane (CBM) production of any basin in the world along the border of the two states.
Historical highlights of coalbed methane (CBM) development in the basin are as follows:
- 1896—Conventional natural gas first produced commercially.
- 1953—Natural gas pipeline constructed to West Coast market.
- 1953—First coalbed methane (CBM) well completed in the New Mexico portion of the basin by Phillips Petroleum Co.
- 1977—First coalbed methane (CBM) well drilled by Amoco.
- 1991—2,032 wells producing; 270 Bcf coalbed methane (CBM) produced during 1991.
- 1992—359.2 Bcf methane produced from Fruitland in first 10 months.
- 2000—coalbed methane (CBM) well spacing reduced to 160 acres from 320 acres.
- 2003—810 Bcf methane produced from Fruitland coals during 2003.
The basin has experienced highly successful coalbed methane (CBM) production because of favorable coalseam thickness, permeability, gas content, depth, and coal rank in a large area. Development of the coals for methane was assisted by extensive drilling in previous decades into the gas-containing Pictured Cliffs sandstone below the coals, which resulted in an in-place infrastructure to handle the gas.
Additional data came from mining in the basin near outcrops. The high flow rate of some of its wells makes it the leading producer in the United States and a model for exploration in the other countries.
Individual seams occur up to 40 ft thick, and net thicknesses of coal in a single well may reach 100 ft, although average net thicknesses of 30–50 ft are common., The basin is conveniently divided into three areas that have substantially different coal reservoir properties (see Fig. 1.10). Area 1 of Fig. 1.10 represents the heavily drilled area of high permeability, high rank, and overpressuring, so most of that area represents a fairway of prolific production. Production from the Cretaceous coals in the basin is assisted by a permeability of 1.5–50 md with an average of 5 md realized over the Fruitland formation and with 50 md occurring in highly fractured areas.
Fig. 1.10—San Juan basin’s three zones for coalbed methane (CBM) producibility.
The coals are ranked as high as low-volatile bituminous in the north to as low as subbituminous B in the south, their rank not necessarily dependent on present burial depth. The critical level of rank in the basin for the most successful wells, which are cavity completed, is hvAb. Even the next lower rank of hvBb encounters much less success. Large amounts of in-place gas, about 50 Tcf in the Fruitland formation, exist because of thick seams, high gas content, and large areal extent. The favorable permeability means extensive reserves of methane estimated for the basin. The estimated gas in place for the Menefee coals in the San Juan basin is approximately equivalent to 34 Tcf.
Favoring coalbed methane (CBM) production in the basin is the relatively high gas content of the coals in Area 1. The gas content ranges from 300–600 scf/ton. The inorganic matter is a high 10–30% in the Fruitland coals, and the ash content from proximate analysis is most commonly near 20%. High mineral matter content reduces methane content, increases cleat spacing, and may create an anomaly in gamma ray readings of well logs (affects the mineral’s variability in radioactivity).
It is estimated that 350 billion tons of coal exist in the basin.6 In the Fruitland coals, 50 Tcf of in-place methane are present at depths between 400–4,200 ft, and 11 Tcf of the methane has been recovered so far, with possibly another 20 Tcf that could be recovered.
Although coal is found throughout the Cretaceous sediments of the basin, the Fruitland formation (100–600 ft thick) is the primary coal-bearing stratum and the main target. The Fruitland is extensive, containing 16 seams spread over 7,500 square miles of the basin. It has 2–14 seams in the depth interval of 2,500 to 3,800 ft. Logan gives a typical example of the Fruitland: at a depth of 3,100 ft in a 170-ft interval, shale and sand lenses reduce the net coal thickness to a typical 54 ft in the interval. Individual seams are discontinuous, but the coal persists over most of the basin. Fassett found that single seams do not continue beyond 2–25 miles. The thickest seams occur in the overpressured northern part of the basin (Area 1 of Fig. 1.10) and contain about 35 Bcf/sq mile of methane.
Located below the Fruitland, the Pictured Cliffs sandstone, target for conventional gas reservoirs, formed the base of the Fruitland peat swamps as the Cretaceous Seaway regressed.47 Historically, while drilling the 17,000 oil and gas wells in the basin, companies considered it a nuisance to drill through the coal. In these sandstone formations below the coal are located gas reserves second in size in the United States to the Hugoton field of Kansas. Gas in the Pictured Cliffs originated in the coals of the Fruitland formation. In areas where the Pictured Cliffs sandstone intertongues with the Fruitland, the coal and sandstone sources of the produced gas may be indistinguishable. Here, decline curves of the sandstone may resemble those for coal, further indicating their inseparability. The coal has thin, discontinuous laminations of shale and sandstone mingled with it.
In 1992, active wells in the Fruitland coals produced 359.2 Bcf of gas. Wells have an average reserve of 3 Bcf and are drilled on 320-acre spacings. The most prolific well in the basin is that of Meridian Oil, which reached a production plateau in excess of 20 MMcf/D.36 In 2003, active wells in the Fruitland coals produced 810 Bcf gas,38 and the spacing was downsized to 160 acres.
Some problems encountered in the San Juan basin included: (1) altitudes of 5,000–7,000 ft, (2) water salinity necessitating disposal wells, (3) in a few reservoirs, desorbed methane contaminated with 4–6% carbon dioxide, (4) environmental concerns in a national forest, and (5) difficult access to remote locations. Initially, there was limited distribution infrastructure for distributing the gas produced. Yet despite these problems, profitability was high enough in Area 1 of Fig. 1.10 to sustain operations without the tax credit, and 60 companies were drilling and producing coalbed methane (CBM) in the basin at the beginning of 1991.
The coalseams of the Fruitland formation in the northwest are about 30% overpressured because of the outcrop of the permeable formation at a high elevation near Durango, Colorado, where meteoric waters overpressure the steeply dipping coals southward beneath terrain of lower elevation.50 Moreover, the overpressuring is indicative of good permeability in the seams. In the
Northeast Blanco unit of the northwestern part of the basin, pressure gradient is 0.55 psi/ft, as compared to the normal 0.43 psi/ft of the Pictured Cliffs sandstone beneath the Fruitland. The pressure gradient in the Tiffany area of the San Juan basin varies between 0.50 and 0.53 psi/ft. This contrasts with an underpressured southern region.
A deeper formation, the Menefee, has an estimated 38 Tcf of additional gas over an areal extent of 12,000 sq miles, but the Menefee has not yet been developed. It consists of thinner, less continuous beds intermingled with shale. Tables 1.6 and 1.7 summarize some significant facts of the San Juan basin. The low sulfur content of the coals of less than 1% indicates fresh water in the peat-forming swamps that developed inland from the Cretaceous Seaway.
Table 1.6—San Juan Basin Description
Table 1.7—San Juan Basin Producing Horizons
1.7.2 Black Warrior Basin
The coalbed methane (CBM) industry began in the Black Warrior basin of Alabama, and from the basin has come much of the data for development of the process. Research from the Gas Research Institute’s Rock Creek facility and field data from the many companies in the basin made the process viable there, especially for multiple, thin seams that are often marginally profitable. Coal mining in the Warrior for the previous 100 years provided a source of geologic and engineering data that gave impetus to early development. The propitious depths and existing mines allowed field studies and development at reduced economic risk.
Coal mines in the area have experienced safety problems throughout the history of mining there because coals of the Black Warrior are gassy. Deep mines may have 500–600 scf/ton of methane, and 51 mine explosions of methane have killed 974 people over the years. The first explosion occurred in 1911 and killed 128 miners. To make the shafts safer to work, the methane is mixed with air and vented to the atmosphere via multiple fans of 2,000–3,500 hp each.
Another method to rid coals in the Warrior basin of methane began in 1977 with a joint project between the DOE and U.S. Steel to drill a vertical wellbore ahead of a mining operation to demethanize the coal and use the gas on-site for electricity generation. Because the technique proved so successful, it was developed into a stand-alone commercial enterprise. Significant events related to development of the coalbed methane (CBM) industry in Alabama are
- 1886—First coal mining in Alabama’s Warrior basin.
- 1911—First coal mine explosion, 128 killed.
- 1976—23 Well programs of USBM and U.S. Steel began at Oak Grove.
- 1977—Production began at Oak Grove.
- 1977—Test of vertical wellbore to vent.
- 1981—First permit to drill coalbed methane (CBM) well.
- 1983—Rock Creek research site established by GRI.
- 1985—Eastern Region Coalbed Methane Resource Center established by GRI at University of Alabama.
- 1990—Cumulatively, 4,308 wells permitted; 3,587 wells drilled.
- 1992—3,089 wells producing; 92 Bcf produced for the year; 290 Bcf cumulative production.
- 1992—End-of-year demise of the federal tax credit on new wells reduces drilling in basin.
- 1995—Eastern Region Coalbed Methane Resource Center closed.
- 2002—3,474 Wells producing; 116 Bcf produced for the year; 1.4 Tcf cumulative production.
The industry grew rapidly in the Black Warrior basin as the decade of the 1980s progressed, creating a boom atmosphere locally in the midst of an oil and gas industry depression nationwide. The self-start of the industry, centered along a Tuscaloosa-to-Birmingham axis, was assisted by an infrastructure of service companies and accessible pipelines already in place to serve the conventiona natural gas produced from the Black Warrior basin since 1953. About 4,308 wells had been permitted by the beginning of 1991, and drilling expenditures had exceeded $1.138 billion. Production reached 36.5 Bcf for 1990, a 56% increase over the previous year; 1,770 wells were producing in 1990, a 94% increase over the previous year. Production reached 116 Bcf for the year 2002, a 21% increase from 1992 when the tax credit ended. Because producing multiple thin seams is often marginally economical, the termination of the federal tax credit on new wells at the end of 1992 seriously affected drilling in the Warrior basin.
The Black Warrior basin is not considered as profitable as the San Juan basin for the production of methane from coal, primarily because the multiple, thin seams are more difficult and costly to complete and are of limited production rate. However, economic feasibility of coalbed methane (CBM) production in the Black Warrior basin depends on numerous factors. Although economics of producing methane from the coals of the Warrior are hurt by the cost of producing from multiple, thin zones, advancements in completion techniques and fracturing have made the process more profitable. Also, favorable state regulations for surface-water disposal have contributed to economic feasibility; water-disposal costs are generally less than in western basins. The Section 29 federal tax credit, as mentioned previously, was important in establishing marginal economic properties in the basin. Other positive factors include good permeability of the formations, high gas content of the coals, and data from previous coal and natural gas operations. Finally, proximity to gas pipelines and infrastructure in the basin helped make the coal gas commercially attractive.
Coal seams in the 18,000-sq mile Black Warrior basin, from which methane is commercially produced, range in depth from 500 ft in the Cobb seams to 4,500 ft in the Black Creek seams. However, the most productive depths are at about 1,500 to 3,000 ft. Individual seam thicknesses run from 1 ft or less to 8 ft with multiple seams occurring over a 1,000-ft interval. Net thickness of coal seams in any well may reach a maximum of 20–30 ft.
Normal faults occur in this foreland basin and trend northwestward, having displacements of perhaps several hundred feet. The basin covers much of northern Alabama and northern Mississippi, bounded by the Appalachian tectonic belt on the east, the Oauchita front on the south, and the Nashville and Ozark domes on the north.
Roughly one-half of the basin extends into Mississippi, but no mining or coalbed methane (CBM) production has occurred in Mississippi. Reports confirm the presence of coalseams in the Mississippi portion of the basin, but the lack of data has discouraged development. In both the Mississippi and Alabama Warrior basins, much conventional natural gas production has been realized since about 1953. The location of gas-bearing sands below the coal suggests the coal as a source rock throughout the basin.
The coal in Alabama occurs in the Pottsville formation of lower Pennsylvanian Age rock. Four main coal groups occur in the Pottsville formation: Cobb, Pratt, Mary Lee, and Black Creek. The coal groups outcrop in the northern part of the basin. Additionally, a later interest has been shown in the Gwin group above the Cobb and the J-Interval below Black Creek. Rank of the coals is medium- to high-volatile bituminous, the Black Creek group being of higher rank. The coals generally have low ash content, low sulfur content, and high methane content.
Typically, profitable wells in the Warrior basin may produce an average peak rate of 150–400 Mcf/D. Methane content of the gas is a high 96%, and there are negligible amounts of carbon dioxide or nitrogen present. Therefore, heat content is near 978 BTU/Mcf.
A significant factor in establishing the process in the Warrior has been the ground-level treatment and disposal of produced waters. The lack of suitable formations to dispose of produced waters made the procedure necessary and cooperation with government, along with close environmental monitoring, made it successful. By the third quarter of 1990, 52.3 million barrels of water had been produced and disposed of at the surface since the inception of the process.62 By the end of 1993, water production had reached a peak of 107 million bbl; this could be a result of the large number of wells drilled to meet the expiration of the tax credit deadline in 1992. A total of 59 million bbl of water was produced during 2002.53 Part of the decline in water production could be attributed to declining water production from mature wells.
An estimated 20 Tcf of coalbed methane (CBM) exist in the Alabama portion of the Warrior basin. The figure includes neither the expectations of the Warrior basin in Mississippi nor the gas that might exist deeper than 4,200 ft. Tables 1.8 and 1.9 summarize characteristics of the Black Warrior basin coal seams. These are similar to other Pennsylvanian Age coals in the eastern United States and are regarded as a benchmark for the coals of the other basins.
Typically, production is from net coalseam thickness ranges of 15–25 ft of Pratt, Mary Lee, and Black Creek groups.63 The Mary Lee seams are the primary targets because of favorable depth-permeability relationships, gas content, and seam thickness. Although the Mary Lee seams produce the most methane, the deeper Black Creek seams contain the most in-place gas but at lower coal permeability.
Table 1.8—Black Warrior Basin Description
Table 1.9—Black Warrior Basin Producing Horizons
1.7.3 Raton Basin
The smallest of the major coal basins is Raton Mesa, covering 2,200 sq miles astride the northeastern New Mexico border and the southeastern Colorado border. Bounded on the north by the Wet Mountains and bounded on the west by the Sangre de Cristo Mountains, heights of 9,000 ft are reached in the basin.
Late Cretaceous and Paleocene coals in the Raton basin are found in the Vermejo and Raton formations; the upper Raton formation intertongues with the Vermejo. Below the Vermejo is the Trinidad sandstone. The low-volatile bituminous coal exists in seams of 14-ft maximum thickness, averaging 3 to 8 ft in the Vermejo formation and 12-ft maximum thickness in the Raton formation; generally the seams are thin, but they may be numerous for a given well.
Although a few miles is the limit of their trace, as many as 40 seams exist in these formations, with a cumulative thickness of 90 ft from outcrop to a depth of 4,000 ft. Most seams are lenticular and discontinuous. Despite the small areal extent of the basin, coalbed methane (CBM) is estimated by DOE to be as high as 8–18 Tcf of in-place gas. Stevens estimated 10.2 Tcf of methane in place in the basin. A brief description of the basin is given in Table 1.10.
The coals of the basin are found to be the source rock for conventional gas produced from the Trinidad sandstone below the Vermejo formation.11 In regard to their proximity to the coal, charging of their sands from the coal, conventional a510 scf/ton at 1,192 ft reported.
Table 1.10—Raton Basin Description
The coals of the basin are found to be the source rock for conventional gas produced from the Trinidad sandstone below the Vermejo formation.11 In regard to their proximity to the coal, charging of their sands from the coal, conventiona gas production and depositional history, the Trinidad sandstone is similar to the Pictured Cliffs sand below the Fruitland coals of the San Juan basin, although an overpressured region like the fairway of the San Juan basin is not present.66 Note that coalbeds are discontinuous in the Raton basin, and the naming of them is inconsistent (see Table 1.11).
Coal has been mined in the basin since the 1870s from 371 coal mines. Gassy coals are indicated. Tremain68 reports that the coal of the Allen mine had a gas content of 514 scf/ton and that methane at the rate of 410 Mscf/D was vented from the mine during 1974–76, when nearly 2 million tons of coal was produced. Coal reserves of 17 billion tons are estimated for the basin. The gas content of the coal can be characterized as a relatively high 250–569 scf/ton across the basin.
Moderate coalbed methane (CBM) activity began in the basin in the mid-1980s, and the spotty drilling program was not sufficient to define the production potential of the Raton basin. In 1989, Pennzoil began a test program with the drilling of 19 wells in the Vermejo formation shallower than 2,000 ft.26 Amoco has drilled in the basin.
Fifty wells drilled to depths of 1,200–2,000 ft have been shut in. One well was reported to produce 239 Mcf/D upon testing. Six Vermejo wells exhibited initial production of 0–160 Mcf/D and water rates from 41–574 barrels of water per day (BWPD). Water production ranges from 0–1,200 BWPD from the wells. Sixteen wells were abandoned because of excessive water or low gas content. There are several operators currently active in the basin, and they produced 88 Bcf gas from 1,800 wells in 2003. Table 1.11—Raton Producing Horizons Certain drawbacks to commercial coalbed methane (CBM) production in the Raton basin are still present, including:
- Inadequate pipeline infrastructure for markets outside the basin curtails development.
- Thin and discontinuous coalseams.
- Excessive produced waters. coalbed methane (CBM) water is replenished in certain parts of the basin.
1.7.4 Piceance Basin
The Piceance basin in western Colorado is an elliptically shaped basin divided by the Colorado River into one-third of the area south of the river. It contains coal of Late Cretaceous Age that underlies 6,570 sq miles.70 It is one of three basins touching Colorado to give the state an estimated 100 Tcf of coalbed methane (CBM) in place.
Seventeen companies were active in coalbed methane (CBM) development in the Piceance by 1991. As a result of high gas content and thick seams in the Piceance basin, in-place gas has been estimated at 84 Tcf, but the actual value could range from 30–110 Tcf. The coal is gassy with methane contents reported in the range of 438 to 569 scf/ton. Individual seams are 50 ft thick near Rifle, Colorado. Net thicknesses of seams in single wells are 120 ft in the south and 250 ft in the northeast part of the basin. Important characteristics of the basin are given in Table 1.12.
Table 1.12—Piceance Basin Description
Three primary coal groups exist in the Mesaverde group: Black Diamond, Cameo, and Coal Ridge. The Black Diamond coal group is restricted mostly to the northern one-half of the basin, the Cameo group across the entire basin, and the Coal Ridge group about one-fourth of the basin. The latter two groups of the Williams Fork formation in the southeast, where interbedded sandstone is also a target,72 are the main target seams. The sequence of seams and their characteristics are presented in Table 1.13.
- Black Diamond Coal group—The coals in this group are mostly low-volatile bituminous, which exist as an outcrop to depths of 12,200 ft; maximum cumulative seam thickness is 30 ft. Estimated gas in place in the Black Diamond is 8.8 Tcf.
- Cameo Coal group—The Cameo coals of the Williams Fork formation extend across the 6,600 sq mi Piceance basin even reaching depths of 10,000 ft in the northeast part of the basin. The rank of semi-anthracite, denoting a localized thermal maturity, in the deeper part of the basin is a higher rank than observed in other areas of the basin. A total seam thickness of up to 60 ft exists in the basin and the estimated gas-in-place for the Cameo coals of the Williams Fork formation is 65.2 Tcf. The Cameo coal group contains the most extensive individual coal seams of the Mesaverde group. The coal group can locally be divided into eight seams, which in ascending order are A, B, C, D, E, F, K, and L coalseams. The lowermost “A” and middle “D” seams are the thickest and most extensive coalseams in the basin.73 Separating the “A” coalseam from the additional Cameo group coalseams are interbeds of sandstone, siltstone, and shale. In the Parachute field of Garfield County, wells in the Cameo coals at 5,000–6,000 ft depth average 430 Mcf/D and produce less than 10 BWPD; some of the gas-producing wells produce no water.
- Coal Ridge group—This group exists south of the Colorado River and has an areal extent of 1,600 sq miles. Rank is hvBb to lvb. The Coal Ridge group is the uppermost of the three major target coal groups and usually occurs about 200 ft above the Cameo coal group.75 The Coal Ridge group reaches a maximum depth of 8,000 ft and attains net seam thickness of 40–50 ft. Estimated gas in place is 9.9 Tcf.
Table 1.13—Piceance Basin Producing Horizons
The Gas Research Institute, recognizing the abundance of the resource deeper than 3,000 ft, but with a lack of data to characterize coal at those depths, established a project near Rifle, Colorado to develop technology for producing deep coalbed methane (CBM).
Initial production rates of methane from wells in the basin are reported to range from 14 Mcf/D to 1.5 MMcf/D accompanying 0–2,500 BWPD.71 The following three examples are from the Piceance basin: (1) Wells into Cameo coals at 6,500–7,500 ft averaged 656 Mcf/D and 26 BWPD; (2) a well drilled to 6,502–6,725 ft in the Cameo coal had initial production of 776 Mcf/D and no water;56 (3) Barrett Resources drilled 12 wells of 5,000–7,000 ft into Cameo coals or Mesaverde sandstone. They reported 370–900 Mcf/D and 20 BWPD. Many Cameo coals are dual-sandstone producers.75 In the first quarter of 2002, Tom Brown, Inc. (currently Encana) reported production of 33 MMcf/D out oftheir White River Dome field (including production from the Mesaverde sands). In 2003, the cumulative production from all the coals in the Piceance basin was 1.98 Bcf from 163 wells. This number will only move up with the increased activity by Encana and other operators.
Although thick seams and good gas content are characteristics of the basin, the coal is deep. Permeabilities that fall below 1 md in the northeastern part of the basin do not provide the natural fracture network for commercial flow rates of gas. In the southeast part of the basin, the permeabilities improve because of structural deformations that have left the rock fractured. In the southeast, the overpressured nature of the coal improves gas content. Overall, however, the depth of the basin gives a low permeability, which is its greatest impediment to development.
1.7.5 Greater Green River Coal Region
The Greater Green River Coal region has an areal extent of 21,000 sq miles, which makes it one of the larger coal regions with methane potential.29 The basin extends from southwestern Wyoming into northwestern Colorado and is bounded on the north, west, south, and east by the Wind River Mountains, Overthrust belt, Uinta Mountains uplift, and Rock Springs uplift, respectively.
Five component basins within the region offer individual potential for coalbed methane (CBM) production: (1) Sand Wash basin of northwestern Colorado and southern Wyoming; (2) Great Divide basin of Wyoming; (3) Hanna basin of Wyoming; (4) Green River basin proper; and (5) Washakie basin in Wyoming. Of these five component basins, the Sand Wash basin has had more coal mined than any other basin in Colorado—7 million tons in 1989. Surface and underground mining of the subbituminous to high-volatile bituminous coal occurs in the Yampa field of the southern part of the Sand Wash basin. Major coalbeds of the Sand Wash basin are in the Fort Union formation (Paleocene) and the Williams Fork and Iles formations of the Mesaverde group (Upper Cretaceous). The older and deeper Mesaverde has coals of higher rank, where individual seam thicknesses of 30 ft and net thicknesses of 18–136 ft occur. The Williams Fork has more continuous and thicker coals than the Iles of the Mesaverde group. In comparison, the Fort Union formation in the north has seams that reach 114-ft net thickness with 50-ft single seams. Depths of the seams in the Sand Wash basin are 2,000–7,000 ft. Meteoric waters enter on the eastern boundary where the Mesaverde outcrops in the mountains.
Consequently, high water production rates are encountered from wells drilled into the coals on the eastern margin. A few pilot projects were initiated by operators active in the Sand Wash basin toward the end of the last decade and into the early part of the present decade. It was found that several factors stood in the way of commercial coalbed methane (CBM) development in the basin:
- Mostly unsaturated coals.
- High water production with aquifer sands lying between the coals.
- Thin coalseams.
- Low to very low permeability.
- Normal to underpressured coalseams.
A summary of some important characteristics of the Greater Green River Coal region is given in Table 1.14. A synopsis of the coal-bearing formations of the basins is presented in Table 1.15.
Table 1.14—Greater Green River Coal Region Description
Table 1.15—Greater Green River Producing Horizons
Coal has been mined from the Frontier formation of the Overthrust belt in Wyoming since about 1900. coalbed methane (CBM) drilling began in 1989 in the region. Wells drilled near Rock Springs, Wyoming show that coals above about 2,700 ft have been naturally desorbed. However, as the coal depths approach 4,000 ft, gas content exceeds 500 scf/ton, and water salinity increases. Mud logs from conventional wells show the presence of gas.
Activity in the Greater Green River Coal region in 199079 included coalbed wells drilled as deep as 7,837 ft in the Mesaverde group and as shallow as 1,453–1,473 ft in the Williams Fork formation. A 904-mile pipeline of 36-in. diameter and 1.2-Bcf/D capacity has been completed from the Green River basin to Bakersfield, California. A pilot study was completed by Barrett Resources (currently Williams) toward the end of the 1990s and early 2000 in the Hanna basin.
There has been no commercial coalbed methane (CBM) production in the Hanna basin. However, there is one successful coalbed methane (CBM) play in the Greater Green River basin. It is the Atlantic Rim coalbed methane (CBM) play, located on the shallow eastern margin of the Washakie basin, in Carbon County, Wyoming. The target coalseams are the Almond and Allen Ridge formations, belonging to the Upper Cretaceous Mesaverde group.
The coals are of subbituminous A to high-volatile C bituminous rank. Merit Energy, Anadarko Petroleum, Double Eagle Petroleum, and Yates Petroleum Corporation are active in this area. Based on adsorption isotherms and measured gas content at initial reservoir pressure, both the Almond and the Allen Ridge coals are fully saturated or slightly undersaturated. The gas contents varied anywhere from 21–266 scf/ton for the Almond coals and 53–295 scf/ton for the Allen Ridge coals. These values are on as-received basis. Pore pressure gradients varied from 0.48–0.67 psi/ft, indicating that these coals are overpressured. Based on some measured data and also based on the high water production (up to 3,000 BWPD) the coals have high permeability in this play. At depths of 1,100 to 2,750 ft, the coal thickness ranges from 40 to 100 ft based on a bulk-density cutoff of 2.0 gm/cc. Water produced is disposed into the Deep Creek sandstone (3,000–4,000 ft deep) or the Nugget sandstone (9,600 ft deep) at rates of 5,000 to 10,000 BWPD and the water quality within the coals ranges from 1,000–1,450 ppm total dissolved solids.
Approximately 10.8 MMcf/D of gas and 48,000 BWPD were being produced as of July 2004 out of the 34 wells in the three pods (Cow Creek, Sun Dog, and Blue Sky Pod) of the Atlantic Rim play area.
1.7.6 Powder River Basin
Thick coals of subbituminous rank occur in the Powder River basin of northeastern Wyoming and southeastern Montana. It is an elongated basin of 25,800 sq miles, trending from the northwest to the southeast. The Black Hills and Big Horn Mountains bound it on the east and west.
The profound characteristic of the basin is the extraordinary thicknesses of individual seams; most of this resource is at a depth of 2,500 ft or less. The record reported in the United States is a 220-ft thick seam near Buffalo, Wyoming in the Wasatch formation (Eocene). Net coalseam thicknesses in the basin reach 300 ft. Near Recluse, net thicknesses of seams average 150 ft. Since the shallow coals are not thermally mature, gas content is only approximately 71 scf/ton at a depth of 1,200 ft.29 Average gas content of the entire basin has been estimated at 25 scf/ton. Despite the low gas contents, the thick subbituminous seams that comprise 1.3 trillion tons of coal82 hold an estimated 30 Tcf of gas. Of this in-place gas, 16 Tcf may be recoverable83 from shallow wells that can be drilled at low cost.
A summary of important properties of the Powder River basin is given in Table 1.16.
Table 1.16—Powder River Basin Description
The coal-bearing formations are outlined in Table 1.17. The Canyon coalbed of the Tongue River member of the Fort Union formation (Paleocene) is the thickest and most prevalent, and the Tongue River may contain 8 to 10 seams, reaching 200 ft in net thickness. The Wyodak-Anderson bed is locally up to 150-ft thick, averaging 50 to 100 ft. Note: Besides the Tongue River, the Fort Union formation has two other members with thin coalseams, the Tullock and Lebo.
Table 1.17—Powder River Basin Producing Horizons
Sandstone formations, charged with gas from the coal, are dispersed within the coalbeds. It is no surprise then that 20 conventional, shallow gas fields in the area have been discovered in sandstone-interlocked coals since 1916. Moreover, surface seepage of the gas has been reported in the area for many years, including artesian wells charged with methane. The Ft. Union coals are freshwater aquifers. In 1988, 50 wells were drilled into the dry sands between coalbeds, but such production does not qualify for the tax credit. Fracturing was not performed to avoid tapping the aquifers of the coalbeds.
Coal in the Powder River basin has been mined for many years because it has low ash and low sulfur content. Excessive water production in the central part of the basin at 1,000–2,000 ft has made the economics less attractive than the eastern part of the basin where relatively little water must be pumped from the coals at 250–1,500 ft.
Much of the early coalbed methane (CBM) work in the basin has been in northeastern Wyoming in Campbell County.54 The target coalseam is the Wyodak. Since the coal permeability was very high, these coals were not stimulated; instead, they were completed openhole by underreaming. Such openhole completions in the Fort Union formation (211–600 ft) of northeastern Wyoming54,61,72 have had flows that ranged from 10 Mcf/D to 298 Mcf/D with negligible water production.
Generally, the wells in the basin produce 25–500 Mcf/D. The increased activity in this basin over the last 10 years has made it the second-largest coalbed methane (CBM) producer in the United States after the San Juan basin. Cumulative gas production in 2003for Powder River basin was about 344 Bcf from approximately 12,145 wells.
In summary, factors favoring coalbed methane (CBM) production in the Powder River basin are:
- Thick coalseams.
- Low drilling and completion costs.
- High permeability.
- Sands charged with coalbed methane (CBM) at less than 2,500 ft.
Unfavorable characteristics are low-rank coals, low methane content of coals, water disposal and problems with water rights.
1.7.7 Northern Appalachian Basin
The Northern Appalachian basin occupies 43,000–44,000 sq miles in West Virginia, Pennsylvania, Ohio, Kentucky, and Maryland11 and contains an estimated 61 Tcf of coalbed methane (CBM) in place. Residing from outcrop to 2,000-ft deep, the Pennsylvanian Age coals in the basin are shallower than its counterparts to the south, the Central Appalachian and Black Warrior basins. The important seams in the Northern Appalachian basin lie above the Pottsville formation, which contains the seams of the Central Appalachian and Warrior basins.
Because the Black Warrior basin has been characterized and developed so extensively for coalbed methane (CBM), the similarities of the Northern and Central Appalachian basins are often emphasized. Compared to the Black Warrior basin, the Northern Appalachian basin has similar thin seams and cumulative coalseam thicknesses; individual seams of 1–3 ft are normal. Sediment age and structures are similarly of the Carboniferous stratigraphic period with a mean age of about 300 million years ago (m.y.a.). The rank increases to the east because of heat and pressure generated from tectonic activity near the Appalachian front. Because of the extensive mining in the area, the coals are underpressured and produce less water than the Black Warrior basin, although the chloride content and total solids content are higher in the Northern Appalachian basin. Because the coals are shallower, more underpressured, and generally lower rank than the Warrior coals, their gas content is lower at 150–200 scf/ton.
Some important characteristics of the basin are summarized in Table 1.18. The major seams and formations are summarized in Table 1.19. The Allegheny, Conemaugh, Monongahela, and Dunkard groups contain the most important coalseams of Clarion, Kittanning, Freeport, Pittsburgh, Sewickley, and Waynesburg.
Table 1.18—Northern Appalachian Basin Description
The major seams and formations are summarized in Table 1.19. The Allegheny, Conemaugh, Monongahela, and Dunkard groups contain the most important coal seams of Clarion, Kittanning, Freeport, Pittsburgh, Sewickley, and Waynesburg.
Table 1.19—Northern Appalachian Producing Horizons
Important dissimilarities with the Warrior are the lower permeability and longer sorption times of the Northern Appalachian coals. The sorption time is longer than most basins; Hunt25 estimates 100 to 900 days. Thus, longer time required to produce the gas leaves a higher residual gas content of the coals at the economic limit.
Because comparisons are so often made between the Northern Appalachian, Central Appalachian, and Warrior basins, their generalized stratigraphic columns are presented in Fig. 1.11.87 Historically, numerous coalbed methane (CBM) wells were drilled and produced in the Northern Appalachian basin from 1932 until 1980. These wells were unstimulated or inadequately stimulated, producing 12–150 Mcf/D of methane. With proper fracture stimulation and multiple-seam completions, suitable wells have the potential of 200 Mcf/D.
The cumulative methane production from the Northern Appalachian basin in 2003 was 8.5 Bcf. Legal questions on gas ownership and water disposal hampered the early development of the coalbed methane (CBM) production in the basin.
Fig. 1.11—Comparison of Northern and Central Appalachian and Warrior basins.
1.7.8 Central Appalachian Basin
The narrow 23,000-sq mile Central Appalachian basin extends over portions of West Virginia, Virginia, Kentucky, and Tennessee in a northeast to southwest direction with the area of most promise and highest gas content near its center. The Central Appalachian Basin has an estimated 5 Tcf of methane in place.
Again, the Central Appalachian basin has many similarities with the Northern Appalachian and Warrior basins. These similarities are commonly used to describe the basin. Coal is mined as deep as 2,500 ft in the Central basin, deeper than in the Northern Appalachian basin. Methane emissions from mines in the Central Appalachian basin have reached 7 MMscf/D.
Mining in the basin has reduced the amount of water to be removed to achieve gas production (average of 5 to 10 BWPD).89 Gas content and permeabilities are similar to the Warrior basin, but both properties are higher than the Northern Appalachian. The Pennsylvanian Age coal generally ranges from high-A to low-volatile bituminous, a higher rank than accorded its northern counterpart.
Table 1.20 summarizes important characteristics of the central Appalachian basin.
Table 1.20—Central Appalachian Basin Description
Because of coal mining, the coal properties are well characterized. Hunt states that coals near the center of the basin at 1,500–2,500 ft depth have a reported gas content as high as 660 scf/ton; 1,500- to 2,500-ft depths have 500–660 scf/ton coals. Permeabilities range from 2 md to 25 md. Target seams for the Central Appalachian basin are the Pocahontas No. 3, Pocahontas No. 4, Beckley, and Jawbone. Seams average 2–3 ft in thickness, although the range is from inches to 7 ft. Table 1.21 presents the formations and major coal groups of the basin.
Table 1.21—Central Appalachian Producing Horizons
Note: Rank of most of the seams is high-volatile bituminous, but the Pocahontas No. 3 seam tested as high as 660 scf/ton.25 Central Appalachian coals are generally only 80–90% saturated with water. Faulting is not oriented in any particular direction. Although early wells were unstimulated or were inadequately stimulated, productions of 20 to 140 Mcf/D have been reported.25 Average production of 85 wells brought onstream in 1992 was 100 Mcf/D with 4 BWPD; nitrogen foam and limited-entry completions were frequently used. By the beginning of 1992, there were 101 wells operating in the Central Appalachian basin on 80-acre spacing and averaging 100 Mcf/D. The cumulative coalbed methane (CBM) production from the Central Appalachian basin in 2003 was about 62.5 Bcf.
In summary, production prospects are boosted by relatively high permeabilities, low water production, and high gas contents in the Central Appalachian basin.
1.7.9 Western Washington
Western Washington contains a series of small coal-bearing areas, trending north-south, stretching along the western foothills of the Cascade Mountains from the Canadian border on the north to the Oregon border on the south.51 It has the potential of containing between 3.6 and 24 Tcf of methane in place.11 The coal deposits are interbedded with shale, siltstones, arkoses, and conglomerates. They belong to the Eocene Age.
The coals within the Carbonado formation range from 1 to 5 ft in thickness with a maximum thickness of 15 ft. Only a small amount of data exists for the region. Development of the coalbed methane (CBM) process in the region is hampered by complex geology and lack of oilfield services infrastructure.
A lucrative market for the gas and possibly good gas contents of the coals generate the interest. El Paso Energy and Duncan Energy were recently active in the basin. However, commercial production of coalbed methane (CBM) has not been realized in the region, despite these recent efforts and earlier drilling of approximately exploratory wells. In Table 1.22 some characteristics of the region are listed.
Table 1.22—Western Washington Description
1.7.10 Wind River Basin
The Wind River basin includes 8,100 sq miles in west-central Wyoming. Coal underlies much of it to the extent of a 125×45-mile swath. The deepest coals occur near the northern boundary of the basin. Coals at depths of less than 3,000 ft exhibit a rank of subbituminous A. Coal seams are known to exist to a depth of 14,000 ft, but the rank and potential of those below 3,000 ft are not well known. Seam thickness is generally 1–10 ft, but thicker beds are found in a limited area of western Wyoming.
Where the Cretaceous strata outcrop, seven coalfields have been mined. They are Muddy Creek, Pilot Butte, Hudson, Beaver Creek, Big Sand Draw, Alkali Butte, and the Arminto field. Much of the data on the coals of the basin comes from these outcrops. Commercial coal mining began in the basin in 1870. Although mines have operated in the basin, the coal production peaked in the 1920s. Because of the basin’s remoteness and the existence of larger mines elsewhere in the state, coal is no longer produced in the basin.
Extreme topographic features give elevations ranging from 4,400 to 13,000 ft. Only 6.5% of the basin is owned privately. Considerable reserves of oil and gas are present in the area. Coalseam discontinuity presents difficulty in correlating the seams throughout the basin. Tables 1.23 and 1.24 present some characteristics of the basin.
Table 1.23—Wind River Basin Description
Table 1.24—Wind River Producing Horizons
1.7.11 Illinois Basin
The Illinois basin is the largest of the coal basins, with an areal extent of 53,000 sq miles. It is strategically located near major cities, covering much of the state of Illinois, western Kentucky, and southwestern Indiana. Its coals are found in the Pennsylvanian Age rocks shallower than 3,000 ft, and its major seams occur shallower than 1,000 ft.94 The U.S. Geological Survey estimates that 365 billion tons of coal are in the basin. Of the 75 different seams that have been identified, have been mined. The surface and underground mines were operated around the shallow perimeter of the basin, and the coals in the vicinity of these abandoned mines have become a target for coalbed methane (CBM).
Carbondale and Spoon formation coals have been found to have the potential for gas production in the Illinois basin. They vary in thickness from a few inches to over 15 ft. The gas content for the basin varies from a low of 5–6 scf/ton along the shallow areas of the basin, 80–150 scf/ton in the center part of the basin, to 230 scf/ton in the southern part of the basin where the higher-rank coals are present.95 A general range of 150–225 scf/ton95 is obtained from the adsorption data. The gas is mostly of biogenic nature and the coals are undersaturated. In the Illinois basin, the permeability of coals varies from less than 10 md in southern Illinois and western Kentucky and single digits to over 50 md in the central part of the basin.
An increasing number of coalbed methane (CBM) wells are being drilled in the Illinois basin, mostly into closed and abandoned mines. Some characteristics of the coals of the basin are presented in Table 1.25. Based on GRI (now known as GTI) information, the current gas in place in the Illinois basin has been estimated at 21 Tcf, but based on new data available, the current in-place gas is considerably less but still significant. In the Carbondale and Spoon formations, the expected gas-in-place reserves are estimated to be 1.5–5.0 Bcf of gas per section, assuming 15–30 ft of coal. This is dependent on the recovery factor, location, and depth of coals in the basin; further, the calculation does not account for the presence of 15–20% nitrogen. The factors favoring coalbed methane (CBM) production in the Illinois basin are:
- Multiple coalseams from 100–1,700 ft.
- Net coal thickness: 15–35 ft.
- Low water production.
- Strong local and regional gas markets.
- Minimum environmental opposition.
The negatives impacting the development of coalbed methane (CBM) in the Illinois basin are:
- Low gas contents.
- Poor permeability in many areas.
- High nitrogen content.
- Undersaturated coals.
Table 1.25—Illinois Basin Description
1.7.12 Arkoma Basin
The Arkoma basin covers 13,488 sq miles along the border of central Arkansas and Oklahoma. The east-to-west trending basin is about 250 miles long and 20–50 miles wide. Important characteristics of the basin are given in Table 1.26.
As with other coalfields west of the Mississippi River, initial mining began with the extension of the railroad into the territory between 1870 and 1888. The first commercial coal mining began in Oklahoma in 1872. Gas emissions from the mines indicate their gassy characteristics, especially mines in the Hartshorne coals that have high gas content.
The coal groups and formations in the Arkoma basin are presented in Table 1.27. Note the similarities with the Black Warrior basin.
Table 1.26—Arkoma Basin Description
a. Permeability from Hartshorne coal.
Table 1.27—Arkoma Basin Producing Horizons
a. Coals in Savanna formation in Arkansas known as Paris seam and Charleston seam.
b. These three groups contain 93% of basin coal. Most extensive groups.
The three most important coals in the Oklahoma part of the basin are the Hartshorne, Stigler, and Secor. It has been estimated that 10 individual seams that are 1–7 ft thick exist in the Oklahoma part of the basin. The best gas content is reported to be as high as 700 scf/ton at a 3,000-ft depth in Le Flore County. The Hartshorne coalseam is the main target at 600–1,400 ft depth, 3–9 ft thick, and with good permeability of 3–30 md. Coals in the basin are of Pennsylvanian Age.
Even before coalbed methane (CBM) wells had been drilled, extensive conventional gas production occurred from sands interbedded with coal. Historically, conventional natural gas has been produced since 1910–1915 from three fields in the Hartshorne sandstone, which may have been commingled with gas from the coals. Consequently, a widespread infrastructure for gas production exists in the Arkoma basin.
The prospects appear good for the growth of the coalbed methane (CBM) process in the basin. The first 18 commercial methane wells before 1993 produced 50–300 Mcf/D with typical water production rates of only 0.5 BWPD. As an indication of mounting interest, about wells were drilled in 1993. Thus, the coals are shallow, gassy, of optimum rank, 3–30 md permeability, and have low water rates. Further, a pipeline infrastructure already exists. These factors provide a positive economic indicator. According to the Oklahoma Geological Survey, 749 vertical coalbed methane (CBM) wells drilled in the Oklahoma part of the Arkoma basin produced 44 Bcf of gas from 1989–2003. There were 249 horizontal wells drilled in the Oklahoma part of the Arkoma basin; they produced 28 Bcf from 1998–2003.
1.7.13 Uinta Basin
The Uinta Basin of northeastern Utah and northwestern Colorado is a westward extension of the Piceance basin. The best-tested coalfield in the basin has been the Book Cliffs, where cores from test wells were analyzed to have a gas content of 443 scf/ton; mines exist in eight coalbeds. Because of available data on the coals near the mines, early coalbed methane (CBM) developments clustered in the vicinity of the mines. One stimulated coalbed methane (CBM) well in the Book Cliffs field reportedly flowed 120 Mcf/D initially.56 Average gas production of 121 Mcf/D with 318 BWPD is reported. Adjacent sandstones charged with gas from the coals are also targets.
Table 1.28—Uinta Basin Description
Table 1.28 gives a summary of the basin’s characteristics. As more data accumulated, estimates of gas in place were increased by the Utah Geological Survey23 from early estimates of 1–5 Tcf to 8–10 Tcf. Upper Cretaceous, Mesaverde group coals are the main targets. The coals of the Blackhawk formation of the Mesaverde group are sketched and named in Fig. 1.12.23 Production from five wells in coals of the Blackhawk formation of the Mesaverde group averaged 92 Mcf/D and 356 BWPD on 320-acre spacing. Initially, it was necessary to construct pipelines to remedy a marketing problem.
The Ferron coals within the Ferron sandstone are the main targets in the Drunkard’s Wash field. The Ferron coals range from 1,200–3,400 ft in depth with an average depth of 2,400 ft. These are high-volatile, B bituminous coals with a vitrinite reflectance value of 0.69%. The average ash and fixed carbon content of the Ferron coals are 14.6% and 48.6% respectively. The coalbed methane (CBM) activity in the basin picked up in the 1990s and the cumulative production for 2003 was approximately 83 Bcf out of 600 wells.
1.7.14 Cherokee Basin
The Cherokee basin begins near the Oklahoma-Kansas-Missouri border and extends northward along the Kansas-Missouri border. To its south is the Arkoma basin and to the north is the Forest City basin, all part of the Western Interior Coal region.
The Weir-Pittsburgh (3–5 ft thick) is the most important coal at 220 scf/ton gas content; the Mulky seam in the Cabaniss formation and the Rowe and Riverton seams in the Krebs formation are also important.
Wells tend to produce an average 50 Mcf/D. Small amounts of oil of low gravity (degrees American Petroleum Institute) have been reported from the coals. Generally, gas rates have reached as high as 250 Mcf/D, and based on the current activity levels in the basin, it appears that long-term commercial production of coalbed methane (CBM) has been established. In a manner similar to the Arkoma basin, low water production rates and high permeability encourage commercial development of the shallow seams (600–1,200 ft deep). Wells were first drilled to develop the coal resource in 1990, although conventional gas-containing-coal gas was produced commercially many years before targeting the coals. coalbed methane (CBM) production from the northeastern Oklahoma part of the Cherokee basin reached approximately 11 Bcf per year and from the southeastern Kansas part of the basin reached approximately 10 Bcf per year in 2003.
Fig. 1.12—Composite section of coals in Book Cliffs coalfield, Uinta basin, Utah.