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CBM case studies

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Case studies can be instructive in the evaluation of other coalbed methane (CBM) development opportunities. This article summarizes information about projects in the San Juan basin, Black Warrior basin, Unita basin, and Powder River basin in the US; Hedong coal basin in China; Upper Silesian coal basin in Poland; and the Bowen basin in Australia.

San Juan basin

The San Juan basin, located in New Mexico and Colorado in the southwestern U.S. (Fig. 1), is the most prolific CBM basin in the world. It produces more than 2.5 Bscf/D from coals of the Cretaceous Fruitland formation, which is estimated to contain 43 to 49 Tscf of CBM in place.[1]

  • Fig. 1—Map of the San Juan basin showing the approximate location of the San Juan fairway.

    Fig. 1—Map of the San Juan basin showing the approximate location of the San Juan fairway.

Development history

For a long time, the Fruitland formation coals were recognized only as a source of gas for adjacent sandstones. In the 1970s, after years of encountering gas kicks in these coals, operators recognized that the coal seams themselves were capable of commercial gas rates. CBM development benefited greatly from drilling and log data compiled from previous wells targeting the deeper sandstones and an extensive pipeline infrastructure that was built to transport conventional gas. These components, along with a U.S. federal tax credit and the development of new technologies such as openhole-cavity completions, fueled a drilling boom that resulted in more than 3,000 producing CBM wells by the end of 1992.

Coal characteristics

The thickest Fruitland coals occur in a northwest/southeast trending belt located in the northeastern third of the basin. Total coal thickness in this belt locally exceeds 100 ft and individual coal seams can be more than 30 ft thick.[1] The coals originated in peat swamps located landward (southwest) of northwest/southeast trending shoreline sandstones of the underlying Pictured Cliffs formation. The location of the thickest coals (Fig. 1) coincides with the occurrence of overpressuring, high gas content, high coal rank, and high permeabilities in the San Juan fairway ("fairway"). The overpressuring is artesian in origin and is caused by water recharge of the coals through outcrops along the northern margin of the basin. This generates high vertical pressure gradients, ranging from 0.44 to 0.63 psi/ft,[2] which allow a large amount of gas to be sorbed to the coal.

Coal gas in the San Juan basin can contain up to 9.4% CO2 and 13.5% C2+.[3] Chemical analyses suggest that thermogenic gases have been augmented by migrated thermogenic and secondary biogenic gas sources, resulting in gas contents ranging up to 700 ft 3 /ton.[4] Coal rank in the fairway ranges from medium- to low-volatile bituminous and roughly coincides with those portions of the basin that were most deeply buried. Coals in the fairway typically have low ash and high vitrinite contents, resulting in large gas storage capacities and excellent permeabilities of >10 md from well-developed cleat systems.

Southwest of the fairway, Fruitland coals are typically 20 to 40 ft thick and are considerably underpressured with vertical pressure gradients in some areas of less than 0.20 psi/ft.[5] The low gradients are attributable to low permeabilities, low recharge rates along the southern rim of the basin, and hydraulic isolation from the fairway area. The nonfairway coals were buried less deeply than those in the fairway, resulting in lower-rank coals (high-volatile B bituminous) and gas contents of less than 200 scf/ton. The nonfairway coals also have higher ash contents, resulting in poorer cleating and permeabilities of generally less than 10 md.

Between the fairway and nonfairway areas of the basin is a transition zone one to two miles wide[6] that coincides with a slight change in dip, which is referred to as a structural hingeline.[7] Along this hingeline, a combination of faulting, stratigraphic thinning, and diminished coal quality appear to separate the higher-pressure, better-quality coals in the prolific fairway area from the rest of the basin.[4]

Drilling and completions

During the late 1970s and early 1980s, wells in the San Juan basin were completed as cased holes and hydraulically fractured. Skins were often high in these completions because of formation damage from drilling, cementing, or fracturing fluids. In early 1986, Meridian Oil began a pilot project in the San Juan 30–6 area that pioneered the openhole-cavity completion technique.[5]Resulting gas rates often exceeded 1 MMscf/D per well with some wells achieving 10 MMscf/D. It is estimated that 80% of the completions in the fairway area are cavity completions and that their average rate is four times that of hydraulically fractured wells.[8]

Analysis of the data from several hundred San Juan basin wells shows that the most successful cavity completions are those in coal seams with minimum in-situ stress values of 2,080 psia, ash contents of less than 70%, ranks of high-volatile A bituminous or greater, depths of 2,000 to 3,600 ft, and bottomhole pressures of at least 1,370 psia.[9] These characteristics are common in the fairway area, but, in areas where coal properties are less favorable, cavity completions have been largely unsuccessful.

In the nonfairway area, gas rates are much lower, but wells can still be economically drilled and produced. Initial gas rates are highly variable and range from less than 100 to more than 700 Mscf/D.[10] The biggest factor in obtaining economic gas rates appears to be permeability, with some wells producing more than 300 Mscf/D for more than 5 years when permeability exceeds 10 md.

Various completions are used in the nonfairway areas including cased-hole hydraulic fracturing, acid breakdowns, or unstimulated techniques. Initially, these completions are likely to result in more formation damage than cavity completions. However, matrix shrinkage and a decrease in horizontal stresses with production result in a higher absolute permeability, which offsets this initial damage.[11] Maintaining very low flowing bottomhole pressures is critical in nonfairway wells because of low reservoir pressures.[5] Gas compression is essential for economic success, often because pipeline pressures are greater than reservoir pressures.

Well performance

The San Juan basin produces more than 2.5 Bscf/D from more than 3,500 wells. Good wells in the fairway area typically reach a peak rate of 6,000 Mscf/D with an ultimate recovery of 15 Bscf. Permeabilities in these wells exceed 10 md, and the well spacing is typically 320 acres. Abandonment pressures in the fairway are projected to be less than 100 psia, resulting in recovery factors of greater than 70%. In contrast, wells in the nonfairway areas produce at peak rates of only a few hundred Mscf/D. Permeabilities are typically 1 to 5 md, which requires more closely spaced wells and results in lower recovery factors because of higher abandonment pressures.

An average well in the San Juan basin produces at an initial rate of 100 to 400 Mscf/D and 40 to 400 BWPD.[9] Production typically doubles within 2 to 4 years in fairway wells, while flat initial production profiles are more characteristic of nonfairway wells. Decline rates are highly variable, ranging from less than 5% to more than 20% per year. Most fairway wells experienced a "negative decline" for the first several years as gas rates increased, making it difficult to predict peak rates and decline rates thereafter.

Black warrior basin

The Black Warrior basin is located in Alabama and Mississippi in the southeastern U.S. (Fig. 2). The basin contains approximately 20 Tscf of gas resources and 2,700 producing wells in 18,000 sq miles.

  • Fig. 2—Map of the Black Warrior basin showing the location of the Oak Grove and Cedar Cove CBM fields.

    Fig. 2—Map of the Black Warrior basin showing the location of the Oak Grove and Cedar Cove CBM fields.

Development history

Drilling activity began in the 1970s when boreholes were drilled into mining faces and the collapsed roofs of active coal mines to degas them.[12] In 1981, the first pipeline sale of coalbed gas was made from 21 wells associated with the Oak Grove mine. At approximately the same time, companies began drilling coal gas wells not associated with mining operations. U.S. federal tax credits and a reduced state severance tax encouraged this development throughout the 1980s. Development was assisted by an infrastructure of service companies and an accessible pipeline grid already in place.

Coal characteristics

Coal gas in the Black Warrior basin is produced from thin, multiple seams ranging from 1 to 8 ft thick with a typical aggregate thickness of 15 to 25 ft. The seams are distributed over long intervals of 400 to 1,400 ft and produce from depths of 400 to 4,500 ft. The coals are part of the Lower Pennsylvanian Pottsville formation and consist of four groups: Cobb, Pratt, Mary Lee, and Black Creek. The coal rank is high-volatile A to medium-volatile bituminous. The seams generally have a low ash and low sulfur content.

Gas contents vary widely from 250 to 650 scf/ton, and it is quite common for the coals to be undersaturated with gas.[13] The average methane content is approximately 96% with small amounts of carbon dioxide and nitrogen. A few wells in the southern part of the basin have produced small amounts of oil along with the coal gas. Permeabilities range from less than 1 to 25 md.

The highly variable nature of gas productivity in the Black Warrior coals is influenced greatly by depositional systems and structural geology. The depositional system includes channel and sheet sandstones that periodically interrupted peat deposition, truncating coal seams laterally and compartmentalizing the coal reservoirs. Structural features include:

  • Faults that create individual compartments
  • Folds that contain fracture systems that enhance permeability along fold axes
  • Areas of high reservoir stress resulting in lower cleat permeabilities

In some areas, a positive correlation exists between well productivity and the location of wells within mapped fracture systems.[14] In other areas, higher permeabilities can be correlated to lower in-situ stress values.[15]

Drilling and completions

Nearly all wells are cased, perforated, and fracture stimulated to achieve economic production rates. Water fracs are useful in the shallow, higher-permeability coals (Pratt group) in which the objective is to connect the well effectively to the fracture system.[16] For the deeper, lower-permeability coals, more-viscous fluids (cross-linked gels and nitrogen foam) with greater transport capacity are needed. Typically, 90,000 to 180,000 gal of fluid and 125,000 to 150,000 lbm of sand are used. It is critical to understand the stress profile, rock properties, and preferred fracture growth directions to design and execute fracture stimulation properly in these coal seams.

Nearly all coal gas wells in the Black Warrior basin are produced with rod pumps. Gas compressor stations typically handle gas from 30 to 70 wells, compressing the gas to a pipeline pressure of 400 to 700 psia. Approximately 95% of the produced water is discharged into streams. Operators pump the water into storage ponds where it is treated before release.

Well performance

A histogram of gas production data from 1,140 vertical CBM wells in Alabama form a log-normal distribution.[17] The data show that most wells reach their peak production within 4 years. The wells achieve a mean peak gas rate of 107 Mscf/D with values ranging from 35 to 324 Mscf/D within one standard deviation of the mean. These values attest to the wide range of CBM well performance and the difficulty in predicting rates and reserves for possible new well locations.

One of the key producing properties in the Black Warrior basin is the Cedar Cove field (Fig. 2). It contains 517 producing wells and produces approximately 20% of the total coal gas from the basin.[18] The average well in this field is drilled on an 80-acre spacing and reaches a peak gas rate of 150 Mscf/D in 600 days. The well remains at this rate for approximately 4.5 years before declining. Approximately one-third of the wells peak at less than 100 Mscf/D, one-third peak in the 100 to 300 Mscf/D range, and the other one-third peak at more than 300 Mscf/D. Projected average gas reserves are 820 MMscf per well over a 30-year project life.

Drunkard’s wash (uinta basin)

The Drunkard’s Wash unit is located along the western edge of the Uinta basin in Utah (Fig. 3). Drunkard’s Wash is the most productive of several CBM leases discovered in a coal trend 6 to 10 miles wide and 20 to 60 miles long.[19]

  • Fig. 3—Map of the Ferron coal trend within the Uinta basin of Utah showing the location of the Drunkard’s Wash CBM unit.

    Fig. 3—Map of the Ferron coal trend within the Uinta basin of Utah showing the location of the Drunkard’s Wash CBM unit.

Development history

In 1988, Texaco was the first to test the potential of this area with two cored wells. The cores showed high gas contents, and the wells produced at rates of up to 230 Mscf/D and 500 BWPD.[20] Because of a shift to international exploration opportunities, Texaco farmed out 92,000 acres of Drunkard’s Wash to River Gas Corp. in 1991.

River Gas cored a well on this acreage followed by a producer that tested more than 2 MMscf/D.[21] By mid-1992, three producers were connected to an existing gas pipeline. By the end of 1992, 10 additional development wells were drilled and completed.[22] Subsequent development increased the number of wells to more than 400. The expansion strategy consisted of stepping out from the central group of producing wells with core holes to confirm the existence of good reservoir properties and then expanding the development outward.

Coal characteristics

The Drunkard’s Wash unit produces gas from coals associated with the Cretaceous Ferron Sandstone member of the Mancos shale. The sandstone and associated coals are part of a fluvially dominated delta. The average coal thickness is 24 ft, and the coals occur in 3 to 6 seams at depths of 1,200 to 3,400 ft.[21] Although some coal seams split and coalesce over short distances, many are continuous and correlatable from well to well. Tonsteins are common and serve as excellent time-stratigraphic markers for geologic correlation.

The coals dip to the west at approximately 2 degrees, or 200 ft/mile. Superimposed on this dip is a southwest-plunging nose near the center of the unit. Reverse faults with up to 150 ft of throw are aligned parallel to this nose.[21] Repeated sections are common where wells intersect faults, and production data suggest that these faults may compartmentalize the coal seams. Well testing and production indicate excellent permeabilities of 5 to 20 md.[21] Because of artesian conditions, the coal seams are slightly overpressured relative to a freshwater gradient of 0.43 psi/ft.[7]

The coals produce dry gas with methane concentrations of 95.8 to 98.3%.[21] CO2 concentrations range from 0.7 to 2.5%, and N2 concentrations range from 0.42 to 0.82%. The gas specific gravity is 0.57, and the dry Btu content is 987 to 1,000 Btu/ft3. The average in-situ gas content is 425 scf/ton, and the average ash content is 14.6% based on a 1.75-g/cm3 density cutoff. This average gas content value is considered high given that the rank of the coal is high-volatile B bituminous. Isotopic studies suggest that the coals have been enriched by thermogenic gas that has migrated updip from higher-rank coals buried deeper in the basin and late-stage biogenic gas.[7] Interbedded sandstone layers are thought to contribute 10 to 15% of the gas production. Interbedded carbonaceous shales, which have bulk densities of greater than 1.75 g/cm3 and contain significant quantities of methane, are also likely contributors of gas to the wellbores.[23]

Drilling and completions

Wells are air drilled to minimize formation damage with 7.875-in.-diameter bits.[21]Approximately 5% of the wells are cored with a diamond-bit, wireline-retrievable tool that cuts a 2.5-in. core. This system minimizes lost gas and results in core recoveries of 80% or greater. Wells are logged with density/neutron, gamma ray, caliper, and resistivity tools. High-resolution processing of the bulk density logs increases vertical resolution to 0.5 ft, helping to identify the coalbeds.

Wells are completed with cemented 5.5-in.-diameter casing that is perforated and hydraulically fractured in two to three separate treatments. One well was stimulated with a cavity-completion technique, but the results were less than expected; therefore, this technique has not been subsequently used.[24] A typical fracture treatment consists of 56,000 lbm of 12/20 sand and 27,000 lbm of 20/40 sand.[21] The sand is carried in approximately 40,000 gal of water containing a 30-lbm/1,000 gal cross-linked gel. Significant variations in fracture gradient have been observed with values ranging from 0.6 to 1.4 psi/ft.[25] For each well, the drilling and equipment costs are approximately U.S. $200,000, and the fracture-stimulation cost is approximately U.S. $100,000.

In most cases, wells are completed with tubing and rods and produced with a pumping unit.[21] Several high-volume wells are produced with PCPs. In approximately half the wells, gas is produced up the annulus between the tubing and casing while water is produced through the tubing. In the other wells, water and gas are produced up the tubing and separated at the surface. After producing for 6 months to a year, some of the pumping wells produced at high enough gas rates that the pumps were removed. Downhole problems include:

  • Scaling
  • Coal-fines migration
  • Gel damage from the fracture stimulation

In 1997, a series of cleanout and flush jobs was conducted to correct these problems, and gas production increased by approximately 20% per well.

Well performance

The Drunkard’s Wash unit includes approximately 350 wells that currently produce an average of 616 Mscf/D and 175 BWPD per well. 22 Cumulative field production exceeds 210 Bscf with estimated reserves for individual wells ranging from 1.5 to 4 Bscf. This translates into a minimum field recovery of 1 to 2 Tscf. 7 The current well spacing of 160 acres appears to be sufficient on the basis of a pressure monitor well showing a significant reduction in interwell pressure.[21]

Wells typically reach their peak gas rate within 3 to 5 years and remain at this peak for a year or so. Afterwards, the wells decline at approximately 10% per year. In February 1995, after approximately 2 years of production, the wells were shut in for a month to install gas compression. When the wells were returned to production, it took 5 months to return to preshut-in gas rates. This emphasizes the need for constant production in CBM wells to dewater the reservoir and desorb the gas progressively.

A central gas compressor facility increases the gas pressure from 10 psia to more than 500 psia, reducing wellhead pressure and maximizing gas rates.[21] Produced water is injected into seven water-disposal wells in the Jurassic Navajo sandstone at 5,200 to 6,000 ft or is pumped into an 11-acre evaporation pond.[21] Water-disposal costs are approximately U.S. $0.07/bbl.

Powder river basin

The Powder River basin of Wyoming (Fig. 4) has been the recent focus of intense development activity targeting thick, shallow, subbituminous coals with low gas content. Operators drilled more than 4,200 wells in 2001, and estimates call for up to 60,000 new wells by 2011. With more than 1 trillion tons of coal available and gas resources exceeding 7 Tscf,[26] there are plenty of remaining CBM opportunities.

  • Fig. 4—Map of the Powder River basin showing the Marquiss and Rawhide Butte areas.

    Fig. 4—Map of the Powder River basin showing the Marquiss and Rawhide Butte areas.

CBM development in the Powder River basin has been slow because of uncertainties regarding coal reservoir characteristics and concerns that CBM wells could never be produced economically.[27] Early drilling was spurred by U.S. federal tax credits in the late 1980s and early 90s. The first wells were either drilled into deep coal seams because of their higher gas content or drilled into coal seams contained in structural highs (compactional folds) to produce free gas from the cleat system and minimize water production. One of the first commercial projects was in the Rawhide Butte area north of Gillette, Wyoming (Fig. 4), where approximately 90 wells were drilled and produced to remove coal gas adjacent to several large surface mines.[28]

From 1992 to 1994, Rawhide Butte was followed by development projects in the Marquiss and Macsy areas, south of Gillette, which demonstrated economic gas rates and that the coals could be dewatered. These projects pioneered several technological advances in the basin including the use of:

  • Variable-speed pumps
  • Hydraulic fracturing
  • Openhole completions through the coal intervals

Over the last few years, exploration has expanded from the Gillette area to the west side of the basin and northward to the Wyoming/Montana state line. Gas pipeline infrastructure is expanding with several projects underway to increase capacity. The average finding cost has been approximately U.S. $0.25/Mscf, which compares favorably with conventional onshore costs ranging from U.S. $0.15 to $0.50/Mscf.[29]

Coal characteristics

The producing coals of the Powder River basin are contained within the Tongue River member of the Paleocene Fort Union formation. The coals occur in 2 to 24 seams that individually range up to 100 ft thick with a total coal thickness of up to 300 ft.[26] The thickest seams can be correlated regionally, whereas the thinner seams merge and split locally. Typical productive depths are 250 to 1,000 ft. Compared with other U.S. basins, Powder River basin coals are immature with low gas contents and high permeabilities. Gas contents vary from 23 to 70 scf/ton,[26] and permeabilities range from 10 md to more than a Darcy. Well performance in some parts of the basin indicates that the gas content must be considerably higher than the sorbed gas content.[29] Potential sources of this additional gas include:

  • Free gas
  • Dissolved gas
  • Gas that has migrated into the coals from other sources
  • Gas produced from adjacent shales

The produced coal gas composition is approximately 90% methane, 8% carbon dioxide, and 2% nitrogen. The methane is isotopically light, indicating a biogenic origin. The coals have low ash (5%), low sulfur (0.35%), and high moisture (25 to 30%) content. Coal macerals consist of 70 to 90% vitrinite, suggesting a high capacity for gas storage. Limited comparisons of coal isotherms to gas content values indicate that the coals are saturated with gas at depth. The coals are immature, ranging from lignite to subbituminous in rank as indicated by vitrinite reflectance values of 0.28 to 0.45%. Their immaturity also results in large cleat spacings of 3 to 5 in. Pressure surveys indicate that the coals are underpressured relative to a freshwater gradient, with pressure gradients ranging from 0.26 to 0.29 psi/ft.[30]

Drilling and completions

Wells typically are completed in a single coal seam, with a twin well used if multiple seams are present. The minimum completion thickness is approximately 30 ft of coal with well depths ranging from 300 to 1,500 ft. A 9.625-in.-diameter hole is drilled into the top of the coal, and a 7-in.-diameter casing is run and cemented. A 6.25-in.-diameter pilot hole is then drilled through the target coal seam with air, air/mist, or water to minimize formation damage. This hole is underreamed to 10 to 12 in. and cleaned out.[31] Wells are placed on production with a completion rig to run tubing and an electric submersible pump (ESP). The drilling and completion process takes just a few days.

Water is produced up the tubing, and gas is produced up the tubing/casing annulus at bottomhole pressures of 15 to 250 psia. Backpressure helps keep the cleats open and the permeability high. Production typically continues for approximately 2 months to clean up the near-wellbore region before hydraulic fracturing. The purpose of the frac job is to connect the wellbore effectively to the coal cleat system. A typical job consists of pumping 500 bbl of water at 30 to 40 bbl/min at a surface injection pressure of 130 psia.[31] Drilling, completion, and facility costs range from U.S. $65,000 to $95,000[26] per well.

Well performance

Initial gas rates range from less than 100 Mscf/D to more than 1 MMscf/D with 0 to 700 BWPD. Wells ramp up over several years to peak rates of approximately 150 Mscf/D and 50 BWPD. The average well life is projected to be 12 to 15 years with an average estimated ultimate recovery of 300 MMscf per well at an 80-acre well spacing.[26] In 1998, the 625 active wells each produced an average of 140 Mscf/D and 325 BWPD[29] with a cumulative production of approximately 28 Bscf.

Interference between wells is common, especially at well spacings of 40 acres or less, resulting in faster dewatering and quicker gas response. This response is particularly dramatic in wells adjacent to mining areas in which groundwater levels are suppressed by up to tens of meters within a few kilometers of the mines. Produced water is very fresh and can be discharged into streams and livestock ponds, reducing disposal costs and improving project economics. As of 1999, approximately 10,000 acre-ft of water was being produced annually from CBM wells in the basin.

Hedong coal basin

The People’s Republic of China contains an estimated 1,567 billion tons of coal,[32] which is the third-largest coal resource of any country in the world. By the early 1990s, it was recognized that these coals contain CBM resources estimated at 500 to 1,000 Tscf of gas in place.[33] To test the potential of these resources, several CBM projects have been initiated. One of these projects is in the Hedong coal basin, which is located along the eastern flank of the Ordos basin approximately 400 miles southwest of Beijing (Fig. 5).

  • Fig. 5—Map of eastern China showing the location of the Hedong CBM prospect within the Ordos basin.

    Fig. 5—Map of eastern China showing the location of the Hedong CBM prospect within the Ordos basin.

Development history

Coal is mined extensively from a north/south trending outcrop belt along the eastern edge of the Hedong coal basin. Downdip from the mines, several hundred core holes were drilled in the 1950s and 1960s demonstrating the existence of thick, gassy coals over a very large area. Analysis of this data indicates that within the Hedong coal basin, coal gas in place could exceed 10 Tscf.

In 1992, Enron signed an agreement with the Chinese government to assess the CBM potential of the Hedong coal basin. In early 1993, Enron drilled two core holes, which showed favorable coal thickness and gas content. That same year, the Hedong Prospect was chosen as the best CBM prospect in China on the basis of analysis of eight prospective areas.[34] This led to the establishment of the Liulin pilot project, a 3-year cooperative venture between the Chinese government and the United Nations, to demonstrate the CBM potential of the Hedong area. This project consisted of a seven-well pilot that averaged 35 to 106 Mscf/D per well with a peak of 247 Mscf/D in one well.[35]

Coinciding with the Liulin pilot, Enron drilled seven appraisal wells from late 1993 to 1995 to evaluate the Hedong prospect. Several of these were completed, and some produced at water rates of 315 to 1,195 BWPD, indicating good reservoir permeability. ARCO purchased Enron’s interest in mid-1997 and signed production-sharing contracts (PSCs) with China United Coalbed Methane in mid-1998 to appraise a 2,000 sq mile area. Texaco joined the project shortly thereafter, and by mid-2001, 26 wells had been drilled including a five-well pilot and a nine-well pilot. The purpose of the pilots is to determine if the coals can be dewatered, if increasing gas rates will accompany this dewatering, and to determine how to optimize the completion and lifting techniques. The biggest challenges facing the project are the demonstration of commercial gas rates, the confirmation of sufficient reserves for commercial development, and access to potentially large gas markets located hundreds of kilometers away.

Coal characteristics

Coal seams in the Hedong coal basin are part of the Upper Carboniferous Taiyuan and Lower Permian Shanxi formations. Each well contains up to 10 coal seams distributed over an interval 490 to 660 ft thick.[35] Cumulative coal thickness varies from approximately 25 to 65 ft, with individual seams ranging up to approximately 16 ft in thickness. The coal seams dip gently westward at 5 to 10 degrees with a superimposed anticlinal nose and graben suggesting a tensional stress regime that may contribute to higher permeabilities. The coals extend from the outcrop to the deepest part of the Ordos basin, but only those coals at depths of 1,000 to 4,000 ft have been targeted for their CBM potential. Drilling in the area indicates that seams shallower than approximately 1,000 ft do not have high enough pressures to retain commercial quantities of gas, while seams deeper than approximately 4,000 ft do not have sufficient permeabilities to produce at commercial rates.

Two wells have been cored continuously from above the shallowest coal seam to below the deepest seam. The core descriptions show that the Taiyuan formation consists of thick (0.1 to 4.5 m), vitrinite-rich (45 to 57%), and high-sulfur (1.2 to 4.8%) coals. These coals are interbedded with fractured carbonates, but well tests indicate that the carbonate permeabilities are low. Coals of the overlying Shanxi formation are thinner (0.1 to 1.75 m), contain less vitrinite (31 to 55%), and have a lower sulfur content (0.4 to 0.6%). The Shanxi coals are thinner because of the erosive effect of fluvial and distributary channels. These coals contain less vitrinite and more ash because of the addition of material deposited from channel floodwaters. The sulfur content is lower because of the greater distance from the sea. Ash content ranges from 5 to 25% and is dominated by dispersed and layered clays. Petrographic analysis shows that the inertinite content of the Hedong coals is relatively high (30 to 60%) and cleat spacing effectively doubles as the inertinite content doubles, implying lower permeabilities in more inertinite-rich coals.

The coal rank for the Hedong area increases southward from high-volatile A bituminous to semianthracite coal. Gas contents range from less than 150 to more than 500 scf/ton, reflecting variations in coal rank, composition, depth, and degree of saturation. Residual gas is low, ranging from approximately 12.8 to 32.0 scf/ton. Desorption of the coal core samples shows that the gas composition is approximately 96% methane, 3% nitrogen, and 1% carbon dioxide. Comparisons of the desorbed gas volumes with isotherms indicate that the coals are saturated to significantly undersaturated with gas. The undersaturation may result from the uplift and erosion of overburden strata, followed by reburial of the coals under Quaternary and recent loess.

Pilot and appraisal wells drilled in the central part of the Hedong coal basin are normally pressured, but three downdip wells show a conspicuous departure from this trend. SG-1 and SG-2 are overpressured, and SH-2 is underpressured. These observations imply hydraulic connectivity among the central wells and hydraulic isolation from the downdip wells because of:

  • Reduced permeability
  • Faulting
  • Facies changes
  • Thinning of the coals

The potentiometric surface for one of thickest coal seams, Seam 8, is above ground level along the Qiushui River, resulting in artesian flow. Mining core holes along the river report up to several hundred barrels per day of water production and gas burning with a flame up to 1 m in height. Based on this strong upward flow potential and a coal thickness of 65 ft, this area was selected for the first five-well pilot.

Drillstem tests and injection/falloffs have been conducted in nearly every well and show a very wide range of calculated permeability values. For example, in the five closely spaced San Jiao pilot wells, permeabilities for the thickest coal seam (Seam 8) range from 7 to 450 md. In addition, pressure data obtained after several months of production show a greater pressure decline in those wells aligned parallel to the face cleats (east/west direction) than perpendicular to them (north/south direction). This confirms the existence of directional permeability in the face cleat direction, creating elliptically shaped drainage areas and causing interference between wells.

Drilling and completions

The Hedong wells are drilled with low-fluid-loss, water-based bentonite muds. Coring is conducted with wireline-retrievable equipment resulting in trip times of less than 20 minutes, which minimizes the lost-gas volumes. Wells are logged with a combination of gamma ray, spontaneous potential, resistivity, neutron, and density tools. The casing program typically includes a 9.625-in.-diameter surface casing and a 7-in.-diameter completion string. The coals are perforated selectively from the bottom to the top to conduct injection falloff tests in each seam. Openhole cavity completions were attempted in some of the early wells with mixed results. Some wells failed to cavitate, while in others, the flow of coal could not be stopped as the cavity grew up beyond the casing shoe and caused the well to fail. The coal seams are moderately to highly stressed, with fracture gradients ranging from 0.7 to 1.3 psi/ft.

Depending on the well-test results, the seams are completed in several different ways. In coal seams with permeabilities of less than approximately 10 md, gel-based fluids are used to prop a narrow fracture with a long half-length. These fracs typically include 115,000 lbm of sand, 1,300 bbl of 2% KCl water, and a 40-lbm linear hydroxyethyl cellulose polymer gel followed by an ammonium persulfate breaker. In higher-permeability seams (>10 md), a slickwater (KCl) fracture stimulation is conducted to connect the wellbore effectively with the coals. These jobs typically include 2,390 bbl of 2% KCl fluid and 86,000 lbm of sand. An iridium tracer (Ir192) is commonly used so that a post-frac gamma ray log can be run to discern the fracture height. If the permeability is very high (> 100 md), no fracture stimulation is used.

The cost to drill and case a Hedong well is approximately U.S. $100,000. Fracture stimulations cost approximately U.S. $120,000 per well, which includes two frac stages (one for the upper seams and one for the lower seams). An additional U.S. $30,000 per well is spent for tubing, a flowline, a pump, and a separator. Different types of artificial lift have been used including rod pumps on lower-rate wells and ESPs or PCPs on higher rate wells. Water is produced up the tubing, and gas is produced up the annulus. A small backpressure of 50 to 100 ft of fluid is maintained over the pump. The produced gas is flared, and the produced water is used for irrigation.

Well performance

CBM well performance in the Hedong coal basin has been highly variable. Widely spaced appraisal wells drilled and completed by Enron in the mid-1990s showed performance ranging from virtually no water production to hundreds of barrels of water per day. Four appraisal wells drilled in the southern part of the Hedong prospect during 1997–98 had low well-test permeabilities of < 1 to 6 md, with each well producing approximately 20 Mscf/D and 20 BWPD. In 1999, five wells were completed in the San Jiao pilot at a well spacing of 30 acres. After approximately 18 months of production, rates for these five wells ranged from 25 to 50 Mscf/D and 50 to 900 BWPD, with higher rates corresponding to higher well-test permeabilities. In 2000, a second five-well pilot was established at Qikou. Rates for these wells were similar to those of the San Jiao pilot.

Although the permeabilities in several of the pilot wells were very encouraging, the gas content, gas saturations, and isotherm character of the coals were all less favorable than expected. Most significantly, the average coal seam gas saturations ranged from approximately 37 to 56%. Numerical simulation studies indicate that values below approximately 75% result in gas rates that are an order of magnitude lower than those for fully saturated coal seams. Early gas rates of 50 Mscf/D for the pilot are consistent with significantly undersaturated coals. After 2 years of production and an expansion of the San Jiao pilot from five to nine wells, the pilot wells are still producing gas at similar rates, even though the produced-water volumes and reservoir pressures have declined.

To determine if these producing characteristics are regional in extent, a second five-well pilot has recently been completed to the south of the first pilot in an area where the coal quality appears to be better. Individual wells here have peaked at rates as high as 250 Mscf/D.

Upper silesian coal basin

The Upper Silesian coal basin occupies an area of approximately 2,860 sq miles along the border between Poland and the Czech Republic (Fig. 6). Gas resource estimates for the basin vary widely, ranging from 7 to 46 Tscf.[36] The Polish coal industry has collected a significant amount of data from active mines and 150 core holes over the last several decades to evaluate the deep coal mining potential of the area. These data are critical for characterizing coal seam distribution, understanding basic properties of the coals, and formulating a CBM evaluation strategy.

  • Fig. 6—Map of the Upper Silesian coal basin in Poland showing the leases held by the former Texaco and Amoco companies.

    Fig. 6—Map of the Upper Silesian coal basin in Poland showing the leases held by the former Texaco and Amoco companies.

Development history

In 1993, Amoco received one of the first CBM concessions in the basin, covering an area of approximately 121,000 acres.[36] As part of the concession agreement, Amoco agreed to drill 15 wells and production test at least eight of them within the first 3 years. The objectives of these wells were to evaluate gas saturations and permeabilities of the coal seams and to identify intervals that could be used for produced-water disposal. In 1997, Texaco was awarded a concession to the west of Amoco’s acreage after agreeing to drill eight wells in an 18-month initial exploration phase.[37] With gas saturation and permeability data from previous CBM wells in the area, Texaco sited and drilled a five-well pilot on a 40-acre pattern. This enabled them to evaluate the CBM potential of the area quickly and decide their future activities.

Coal characteristics

Coal seams of the Upper Silesian basin are of Carboniferous age and range from 980 to more than 7,200 ft in depth. The average total coal thickness exceeds 160 ft, with the thickest coal seams ranging up to 80 ft thick.[36] The basin is structurally complex with three major normal faults dividing both the Amoco and Texaco concessions. Throws on these faults range from 500 to more than 3,300 ft. Smaller normal faults, with throws of tens of meters, are very common and compartmentalize the reservoirs into dozens of blocks averaging 4,600 ft across.[37]

On the basis of an analysis of more than 1,640 ft of coal, Amoco’s work showed highly variable gas contents and gas saturations.[36] Gas contents from 700 canister samples ranged from nearly 0 to approximately 365 scf/ton. On the basis of 32 isotherms, the saturation state of the coals ranged from 100% saturated in some of the deeper seams to significantly undersaturated. Gas analyses indicated an average composition of 91% methane, 4% C2+, 3% CO2 , and 2% N2 . Thirty well-test permeabilities showed values ranging from less than 0.1 md to more than 50 md.

Texaco’s work also showed significant variations in gas content and saturation state.[37] The coals are slightly undersaturated just beneath the Miocene/Carboniferous unconformity and become increasingly undersaturated with depth. This trend reverses at depths of greater than 1,970 ft, where the coal gas contents increase to 160 to 320 scf/ton and the coals become moderately undersaturated (35 to 80% gas saturated). Coal seams in this interval were completed in the five-well pilot. The variations in gas saturation are the result of a complex succession of burial, uplift, degassing, reburial, and resaturation. The residual gas content of coal samples from the pilot’s center well averaged 32% of total gas. This is a high value, which is consistent with the low diffusion rates measured by Amoco.

Texaco’s work also showed that coal rank increases with depth, ranging from high-volatile B bituminous in shallow coals to low-volatile bituminous in the deepest coals.[37] Coal rank increases much faster below a depth of approximately 3,300 ft, coinciding with the appearance of higher gas contents. This inflection point may be useful for delineating the location of high gas content coals in other parts of the basin. Produced gas from Texaco’s pilot wells consisted of approximately 91% methane, 4% ethane and heavier hydrocarbons, 2% nitrogen, and 3% carbon dioxide. Analysis of 25 openhole injection/falloff tests in the five-well pilot area showed absolute permeabilities of approximately 3 md at a depth of 3,600 ft, decreasing to 1.5 md at 4,600 ft.

Drilling and completions

Texaco fulfilled its eight-well commitment in 6 months by drilling three exploration and five pilot wells.[37] Two of the exploration wells were drilled to the west and north of the pilot to assess the CBM potential of these areas. A third exploration well was drilled to assess the water-disposal capacity of Tertiary sandstones and conglomerates. The pilot wells were drilled as straight holes with water-based muds. The pilot’s center well was cored continuously through the target interval with wireline-retrievable tools to a depth of 4,950 ft. Core recovery was approximately 95% and trip times averaged less than 15 minutes, minimizing the amount of lost gas. The five pilot wells were each completed in approximately 30 ft of coal at depths from 3,660 to 4,580 ft.

The casing program included 13.375-in.-diameter surface casing to 165 ft, 9.625-in.-diameter intermediate casing to 1,310 ft, and 7-in.-diameter production casing to total depth. Wells were perforated and hydraulically fractured in three stages with 45,000 gal of cross-linked gel and 150,000 lbm of sand proppant per stage. Breakdown pressures varied from 4,500 to 6,000 psia, and injection rates ranged from 25 to 50 bbl/min. The stimulations were highly successful with no screenouts or significant flowback problems. Following the frac jobs, the wells were placed on pump and produced for 6 months.

Well performance

Texaco’s five-well pilot attained an early production peak of less than 150 Mscf/D with declining production thereafter.[37] Numerical simulation work indicates that this performance is consistent with relatively low gas contents, moderate undersaturation, and low permeabilities. The relatively steep decline in production suggests a reduction in the effectiveness of the stimulation or completion as the result of plugging, the loss of proppant, or other factors. Alternatively, depressuring the near-wellbore region may have caused swelling of the coal matrix because of gas expansion, reducing the absolute permeability. This can profoundly affect production rates, especially in reservoirs with low initial permeabilities. Because of well performance and simulation work results, Texaco relinquished rights to the Polish concession in late 1998.

Bowen basin

Australia contains estimated total coal resources of more than 450 billion tons. 5 Most coals are of Permian age with the largest deposits found in the Bowen/Gunnedah/Sydney basin system in eastern Australia. These basins have been the focus of numerous exploration and appraisal projects since the mid-1970s. The level of activity has increased significantly in the past few years, resulting in modest commercial production from three fields in the Bowen and Sydney basins.[37] Exploration has expanded to other basins, including the Surat basin, where wells are being drilled to assess the Middle Jurassic Walloon coals.[38]

Development history

The Bowen basin (Fig. 7) has long been recognized as a potential CBM giant with an estimated resource base of at least 178 Tscf.[39] As far back as 1976, wells were drilled adjacent to existing mines to produce coal gas. In 1987, an eight-well pilot was initiated in the Broadmeadow gas field of the Northern Bowen basin, resulting in low-rate gas production.[40] This was followed by more than 120 production wells and core holes over the next 10 years in an attempt to establish commercial production. This goal was achieved in February of 1998 with the first sale of gas from the Comet Ridge field. A second field, the Scotia field, began selling gas in 2002. The Bowen basin has also become a prime target for CO2 sequestration projects. A recent international study identified the Dawson River site, in the southern Bowen basin, as the best location for a CO2 -enhanced CBM project among 11 sites evaluated.[41]

  • Fig. 7—Map of eastern Australia showing the location of the Bowen basin and two commercial CBM projects.

    Fig. 7—Map of eastern Australia showing the location of the Bowen basin and two commercial CBM projects.

Coal characteristics

Coal seams in the Bowen basin exhibit a wide range of coal quality and rank characteristics. Lower Permian coals include the Bandanna and Reids Dome Beds, which are productive in the Comet Ridge field. The coals are high-volatile bituminous A and B with low ash contents.[42] They have a cumulative thickness of 50 to 100 ft at a depth of 2,500 to 3,000 ft. The gross production interval is up to 1,000 ft thick and contains 5 to 15 coal seams. Gas contents range from 200 to 400 scf/ton.

Upper Permian coals include the Middle Goonyella coal seam in the Broadmeadow project, the Rangal coals at the Dawson River site, and the Baralaba coal measures in the Scotia field. The Middle Goonyella seam is a medium- to low-volatile bituminous coal that averages 16.2 ft in thickness and occurs at an average depth of 1,640 ft.[40] The average gas content is 458 ft3 /ton on a dry ash-free basis, and the coals appear to be saturated with gas on the basis of the isotherm. Permeabilities range from 0.2 to 1.5 md on the basis of slug and injection/falloff tests.

The Upper Permian Rangal coals at Dawson River are contained in eight seams, 5.6 to 14.4 ft thick at depths of 1,312 to 2,133 ft.[43] The total coal thickness is approximately 75 ft. The coals are well cleated and of high-volatile bituminous rank with ash contents of less than 10%. Gas content values range from 195 to 440 scf/ton, and the seams are normally pressured to slightly underpressured. Well-test permeabilities range from 2.4 to 19.1 md.

The Baralaba coal measures in the Scotia field are lateral equivalents of the Rangal coals. Wells in the Scotia field produce from depths of approximately 2,950 ft, and the coal seams are contained in a conventional four-way dip closure. As a result, the cleat porosity is gas filled, and no dewatering of the coals is required.

Drilling and completions

At Broadmeadow, Wells 1 through 4 were completed with a 5.5-in.-diameter production casing set above the Middle Goonyella coal seam and a 4.5-in.-diameter open hole through the coal.[40] The wells were then fracture stimulated with 141,000 to 168,000 gal of fresh water and 88,000 to 110,000 lbm of 25/52 mesh Townsville sand. High fracture gradients of 0.96 to 1.33 psi/ft in these wells suggest horizontal or T-shaped fracture geometries. Wells 5 through 8 and Well 10 were completed with slotted 5.5-in.-diameter production casing across the coal seam. Wells 6, 8, and 10 were fracture stimulated in a manner similar to the first four wells, while Well 5 was fractured with linear gel and Well 7 was unstimulated. Because the thinking was that horizontal fractures were being generated, water-based fluids were chosen over gel-based fluids in most of the wells to provide greater penetration.[40]

In a 1992 research project at Dawson River, two field trials of the cavity completion technique were conducted. One of these resulted in a partial success, which increased the gas rate 4 to 5 times relative to the initial unstimulated completion.[43] Because of this work and the great success of the openhole cavity technique in the San Juan basin, this completion type is currently being used in the Comet Ridge CBM project.

Well performance

In the Broadmeadow pilot project, Well 3 peaked at 98 Mscf/D and 20 BWPD and Well 8 peaked at 50 Mscf/D and 40 BWPD within one year of their completion. Although formation damage and production problems may have contributed to these low rates, it is doubtful that commercial gas rates could ever be attained given the consistently low permeabilities of less than 1.5 md measured in four wells.

In contrast, the Comet Ridge CBM project attained commercial status in 1998. The project contains approximately 9,600 producing acres in the Fairview field. This field is located in the southern part of authority-to-prospect (ATP) 526, an exploration lease that includes approximately 1,088,000 acres in Queensland. As of 31 December 2000, there were 26 producing wells at Comet Ridge.[44] Sixteen wells were producing gas into a pipeline system, while production from the other 10 wells was being flared at the wellhead during the dewatering process. An additional 10 wells were awaiting completion and/or connection to a gathering system. Production began in February 1998, and approximately 5.5 Bscf had been produced as of 31 December 2000. As of this date, the producing gas rate was approximately 6 MMscf/D with plans to increase this to 10 to 15 MMscf/D. A 20-well drilling program is underway, with the sixth well finished in July 2001. Proven reserves for Comet Ridge are estimated at 430 Bscf. The majority interest owner, Tipperary Oil and Gas Australia, is appraising an additional 1.5 million acres adjacent to Comet Ridge.

Successful appraisal of the Scotia field in the Denison Trough area of the Bowen basin (ATP 378-P in eastern Queensland) has resulted in a declaration of commerciality.[15] Santos Ltd. has agreed to provide up to 9.5 × 108 Btus of gas for power generation over a 10 to 15 year period commencing in 2002. The latest wells, Scotia 11 through 13, were drilled during the second quarter of 2001 and were fractured hydraulically late in the year. Development costs for the project are estimated at U.S. $15 million, with $11 million of this committed to field infrastructure and a gas processing plant. Santos also has been granted additional exploration acreage immediately north of Scotia field and is evaluating its potential.

References

  1. ↑ 1.0 1.1 Ayers, W.B. Jr., Ambrose, W.A., and Yeh, J. 1994. Coalbed Methane in the Fruitland Formation, San Juan Basin: Depositional and Structural Controls on Occurrence and Resources. Coalbed Methane in the Upper Cretaceous Fruitland Formation, San Juan Basin, New Mexico and Colorado ed. W.B. Ayers Jr. and W.R. Kaiser, Bulletin 146, New Mexico Bureau of Geology and Mineral Resources, Socorro, New Mexico, 13–40.
  2. ↑ Langmuir, I. 1916. The constitution and fundamental properties of solids and liquids. Journal of the American Chemical Society 38 (11): 2221–2295.
  3. ↑ Rice, D.D. 1993. Composition and Origins of Coalbed Gas. Hydrocarbons from Coal, American Association of Petroleum Geologists Studies in Geology 38, ed. B.E. Law and D.D. Rice, American Assn. of Petroleum Geologists, Tulsa, Oklahoma, 159–184.
  4. ↑ 4.0 4.1 Tyler, R. et al. 1997. The Application of a Coalbed Methane Producibility Model in Defining Coalbed Methane Exploration Fairways and Sweet Spots: Examples from the San Juan, Sand Wash, and Piceance Basins. Bureau of Economic Geology, The University of Texas at Austin, and the Gas Research Inst., Report of Investigations No. 244, 59.
  5. ↑ 5.0 5.1 5.2 Close, J., Woolverton, S., and Swainson, K. 1997. Non-Fairway Underpressured Fruitland Coal Resource Characterization Study, Southern San Juan Basin, New Mexico. Proc., 1997 Intl. Coalbed Methane Symposium, Tuscaloosa, Alabama, May, 23–32.
  6. ↑ Combes, J.M. et al. 1997. The Southern Boundary of the San Juan Basin Coalbed Methane High-Production Fairway, New Mexico, U.S.A. Proc., 1997 Intl. Coalbed Methane Symposium, Tuscaloosa, Alabama, May, 567–575.
  7. ↑ 7.0 7.1 7.2 Ayers, W.B. et al. ed. 1991. Geologic and Hydrologic Controls on the Occurrence and Producibility of Coalbed Methane, Fruitland Formation, San Juan Basin. Topical report, Gas Research Inst. contract no. 5087-214-1544, GRI 91/0072, The University of Texas, Bureau of Economic Geology, Austin, Texas, 314.
  8. ↑ Kelso, B.S. 1994. Geologic Controls on Open-Hole Cavity Completions in the San Juan Basin. Quarterly Review of Methane from Coal Seams Technology 11 (3 and 4): 1–6.
  9. ↑ 9.0 9.1 Ramurthy, M., Rogers, R.E., and Weida, D. 1999. Analysis of the Success of Cavity Completions in the Fairway Zone of the San Juan Basin. Presented at the SPE Rocky Mountain Regional Meeting, Gillette, Wyoming, 15-18 May 1999. SPE-55603-MS. http://dx.doi.org/10.2118/55603-MS.
  10. ↑ Ross, S.A., Westerfield, R.W., and Jaffe, J. 1999. Corporate Finance, fifth edition. New York City: McGraw-Hill Book Co. Inc.
  11. ↑ Mavor, M.J. and Vaughn, J.E. 1997. Increasing Absolute Permeability in the San Juan Basin Fruitland Formation. Proc., 1997 Intl. Coalbed Methane Symposium, Tuscaloosa, Alabama, May, 33–45.
  12. ↑ Pashin, J.C. 1999. Coalbed Methane in Alabama: An Overview. Field Trip Guidebook, Trip 1: Characteristics and Origin of Coalbed Methane Reservoirs in the Cahaba Coal Field, ed. J.C. Pashin and R.E. Carroll, 1999 Intl. Coalbed Methane Symposium, Tuscaloosa, Alabama, May, 1–10.
  13. ↑ Rock Creek Multiple Coal Seams Project. 1995. Final report, Gas Research Inst. contract No. 5087-214-1457, Taurus Exploration Inc., 110.
  14. ↑ Briscoe, F.H. et al. 1988. A Study of Coalbed Methane Production Trends as Related to Geologic Features, Warrior Basin, Alabama. Coalbed Methane, San Juan Basin, 237-246. Denver, Colorado: Rocky Mountain Assn. of Geologists.
  15. ↑ 15.0 15.1 2000 Annual Report. 2000. Adelaide, Australia: Santos Ltd.
  16. ↑ Sparks, D.P., McLendon, T.H., Saulsberry, J.L. et al. 1995. The Effects of Stress on Coalbed Reservoir Performance, Black Warrior Basin, U.S.A. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 22–25 October. SPE-30734-MS. http://dx.doi.org/10.2118/30734-MS.
  17. ↑ Fracturing Experience at the Rock Creek Multiple Coal Seams Project. 1995. Topical report, Gas Research Inst. Contract no. 5087-214-1457, Taurus Exploration, Inc. and Stim-lab Inc., 137.
  18. ↑ Pashin, J.C. 1997. Productivity of Coalbed Methane Wells in Alabama. Proc., 1997 Intl. Coalbed Methane Symposium, Tuscaloosa, Alabama, May, 65–74.
  19. ↑ Hobbs, G.W., Holland, J.R., and Winkler, R.O. 1997. Updated Production and Economic Model for Cedar Cove Coalbed Methane Field. Proc., 1997 Intl. Coalbed Methane Symposium, Tuscaloosa, Alabama, May, 75–86.
  20. ↑ Montgomery, S.L., Tabet, D.E., and Barker, C.E. 2001. Upper Cretaceous Ferron Sandstone: Major Coalbed Methane Play in Central Utah. American Assn. of Petroleum Geologists Bulletin 85 (2): 199.
  21. ↑ 21.00 21.01 21.02 21.03 21.04 21.05 21.06 21.07 21.08 21.09 21.10 Burns, T.D. and Lamarre, R.A. 1997. Drunkards Wash Project:Coalbed Methane Production from Ferron Coals in East-Central Utah. Proc., 1997 Intl. Coalbed Methane Symposium, Tuscaloosa, Alabama, May, 507–520.
  22. ↑ Lyle, D. 1991. First Well in Utah Coal Gas Program Strikes Pay on 92,000 acre Texaco Farm-out to River Gas. Western Oil World 47 (8): 8–9.
  23. ↑ Lamarre, R.A., Pratt, T., and Burns, T.D. 2001. Reservoir Characterization Study Significantly Increases Coalbed Methane Reserves at Drunkard’s Wash Unit, Carbon County Utah. Paper presented at the 2001 American Assn. of Petroleum Geologists Annual Meeting, Denver, 3–6 June.
  24. ↑ Willis, C. 1995. Drilled Core Holes Key to Coalbed Methane Project. Oil & Gas J. (6 March): 73–75.
  25. ↑ Conway, M.W. et al. 1997. Characterization and Performance of Coalbed Methane Wells in Drunkard’s Wash, Carbon County, Utah. Proc., 1997 Intl. Coalbed Methane Symposium, Tuscaloosa, Alabama, 195–212.
  26. ↑ 26.0 26.1 26.2 26.3 26.4 Ayers, W.B. 2000. Methane Production from Thermally Immature Coal, Fort Union Formation, Powder River Basin. Paper presented at the 2000 American Assn. of Petroleum Geologists Annual Meeting, New Orleans, 16–19 April.
  27. ↑ Peck, C. 1999. Review of Coalbed Methane Development in the Powder River Basin of Wyoming/Montana. Presented at the SPE Rocky Mountain Regional Meeting, Gillette, Wyoming, 15–18 May. SPE-55801-MS. http://dx.doi.org/10.2118/55801-MS.
  28. ↑ Zander, R.A. 1999. Development, Environmental Analysis, and Mitigation of Coalbed Methane Activity in the Powder River Basin of Wyoming. Proc., 1999 Intl. Coalbed Methane Symposium, Tuscaloosa, Alabama, 47–57.
  29. ↑ 29.0 29.1 29.2 Nelson, C.R., Hill, D.G., and Pratt, T.J. 2000. Properties of Paleocene Fort Union Formation Canyon Seam Coal at the Triton Federal Coalbed Methane Well, Campbell County, Wyoming. Presented at the SPE/CERI Gas Technology Symposium, Calgary, Alberta, Canada, 3-5 April 2000. SPE-59786-MS. http://dx.doi.org/10.2118/59786-MS.
  30. ↑ Pratt, T.J., Mavor, M.J., and DeBruyn, R.P. 1999. Coal Gas Resource and Production Potential of Subbituminous Coal in the Powder River Basin. Presented at the SPE Rocky Mountain Regional Meeting, Gillette, Wyoming, 15-18 May 1999. SPE-55599-MS. http://dx.doi.org/10.2118/55599-MS.
  31. ↑ 31.0 31.1 Pratt, T.J., Mavor, M.J., and DeBruyn, R.P. 1999. Coal Gas Resource and Production Potential of Subbituminous Coal in the Powder River Basin. Presented at the SPE Rocky Mountain Regional Meeting, Gillette, Wyoming, 15-18 May 1999. SPE-55599-MS. http://dx.doi.org/10.2118/55599-MS.
  32. ↑ Zhang, X. 1991. Coalbed Methane in China, 150. Xian, China: Shaanxi Science and Technology Publishing House.
  33. ↑ Boyer, C.M. II. 1993. Geologic Evaluation of the Eight Exploration Areas and Site Selection, Geologic Design, and Test Plans for the Exploration/Production Test Wells. Topical report, Project CPR/91/214/A/01/99, United Nations Development Program, New York City.
  34. ↑ Zhang, S. et al. 1997. Coal Fracture Studies of the Eastern Margin of the Ordos Basin: Guides for Coalbed Methane Exploration and Development. Proc., Intl. Coalbed Methane Symposium, Tuscaloosa, Alabama, 225–233.
  35. ↑ 35.0 35.1 Zhang, S. et al. 1997. Coal Fracture Studies of the Eastern Margin of the Ordos Basin: Guides for Coalbed Methane Exploration and Development. Proc., Intl. Coalbed Methane Symposium, Tuscaloosa, Alabama, 225–233.
  36. ↑ 36.0 36.1 36.2 36.3 McCants, C.Y., Spafford, S., and Stevens, S.H. 2001. Five-Spot Production Pilot on Tight Spacing: Rapid Evaluation of a Coalbed Methane Block in the Upper Silesian Coal Basin, Poland. Proc., 2001 Intl Coalbed Methane Symposium, Tuscaloosa, Alabama, 193–204. Cite error: Invalid <ref> tag; name "r37" defined multiple times with different content
  37. ↑ 37.0 37.1 37.2 37.3 37.4 37.5 37.6 Wong, S. et al. 2001. CO2 -Enhanced Coalbed Methane Recovery Demonstration Pilot—A Case for Australia. Proc., 2001 Intl. Coalbed Methane Symposium, Tuscaloosa, Alabama, 75–86. Cite error: Invalid <ref> tag; name "r38" defined multiple times with different content Cite error: Invalid <ref> tag; name "r38" defined multiple times with different content Cite error: Invalid <ref> tag; name "r38" defined multiple times with different content Cite error: Invalid <ref> tag; name "r38" defined multiple times with different content Cite error: Invalid <ref> tag; name "r38" defined multiple times with different content
  38. ↑ Scott, S.G. and Bell, B.M. 2001. Coal Seam Exploration in the Walloon Coal Measures, Northeast Surat Basin, Queensland. Proc., 2001 Intl. Coalbed Methane Symposium, Tuscaloosa, Alabama, 455–468.
  39. ↑ Decker, A.D., White, J., and Reeves, S.R. 1991. Coalbed Methane Exploration Strategies Successfully Applied in the Bowen Basin, Queensland, Australia. Proc., 1991 Intl. Coalbed Methane Symposium, Tuscaloosa, Alabama, 315–330.
  40. ↑ 40.0 40.1 40.2 40.3 Reeves, S.R. and O’Neill, P.J. 1989. Preliminary Results from the Broadmeadow Pilot Project, Bowen Basin, Australia. Proc., 1989 Intl. Coalbed Methane Symposium, Tuscaloosa, Alabama (May 1989) 273–291. Cite error: Invalid <ref> tag; name "r42" defined multiple times with different content Cite error: Invalid <ref> tag; name "r42" defined multiple times with different content Cite error: Invalid <ref> tag; name "r42" defined multiple times with different content
  41. ↑ Wong, S. et al. 2001. CO2 -Enhanced Coalbed Methane Recovery Demonstration Pilot—A Case for Australia. Proc., 2001 Intl. Coalbed Methane Symposium, Tuscaloosa, Alabama, 75–86.
  42. ↑ Goscombe, P.W. and Koppe, W.H. The Bowen Basin, Queensland. Excursion Guide No. 10A, Permian Coal Geology—Eastern Australia, 25th International Geological Congress, Sydney, Australia, Progress Press Pty. Ltd., Canberra, Australia, 1–21.
  43. ↑ 43.0 43.1 Wold, M.B., Davidson, S.C., Wu, B. et al. 1995. Cavity Completion For Coalbed Methane Stimulation - An Integrated Investigation And Trial In The Bowen Basin, Queensland. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 22-25 October 1995. SPE-30733-MS. http://dx.doi.org/10.2118/30733-MS.
  44. ↑ 2000 Annual Report. 2000. Queensland, Australia: Tipperary Oil and Gas (Australia) Pty. Ltd.


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See also

Coalbed methane

CBM basin assessment

CBM reservoir fundamentals

CBM well drilling and completion

CBM production operations

CBM reservoir evaluation

CBM economics

PEH:Coalbed_Methane

Page champions

George J. Koperna, Jr.

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