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Production characteristics and reservoir analysis of coalbed methane reservoirs


International Journal of Coal Geology 38 ?1998. 27–45

Production characteristics and reservoir analysis of coalbed methane reservoirs
Michael D. Zuber
) S.A. Holditch and Associates, 1310 Commerce Dri?e, Park Ridge 1, Pittsburgh, PA 15275-1011, USA Received 8 July 1997; accepted 1 July 1998

Abstract Six Appalachian coalbed methane ?CBM. projects are reviewed and evaluated in terms of reservoir engineering techniques and CBM recoverability. These include three non-mine-related projects in the northern Appalachian basin, one non-mine-related, and two mine-related projects in the central Appalachian basin of southwestern Virginia. Generally, low production rates and low CBM reserves are characteristic of the central and northern Appalachian basin; therefore, minimizing production costs is fundamental to the economic success of a CBM project in these regions. Well deliverability is determined through permeability testing and through production data analysis using a reservoir simulator to history match historic production data. All of the non-mine-related projects utilize vertical wells with well spacings of 60 to 100 acre ?0.23–0.40 km2 . that produce from multiple coalbeds at depths as much as 762 m. The targets are coalbeds of the Pocahontas and New River Formations and correlative Lee Formation. In the Nora Field of Virginia ?Equitable Resources, developer., well spacing is 60 acre ?0.23 m2 ., and recoverability is high ?30–60% of initial gas in place.. Well stimulation is by foam or water as the fracture medium. The average gas in place is 675 MMscf welly1, and the expected lifetime of the wells is 30 years. Cost of water disposal is a major economic factor in CBM development in the Appalachian basin. Water disposal is accomplished by using water disposal holes ?injection wells. rather than surface water discharged, which is generally not permitted. Water disposal in the central Appalachian basin involves relatively low volumes of water ?30 STB dayy1, declining to 1 to 2 STB dayy1 .. In the northern Appalachian basin in Indiana County, PA ?Belden and Blake, developer., vertical CBM holes penetrate six to eight Allegheny Formation coalbeds. Water and a sand proppant are used for stimulation. Production levels are low ?- 100 Mcf dayy1 welly1 .. The life of a vertical CBM hole drilled in advance of mining is 3 to 5 years. This type of hole may be converted to a gob hole after mining is completed. Gob gas is recovered mainly from coalbeds

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0166-5162r98r$ - see front matter q 1998 Elsevier Science B.V. All rights reserved. PII: S 0 1 6 6 - 5 1 6 2 ? 9 8 . 0 0 0 3 1 - 7

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above the mined coalbed and has high recoverability of as much as 10 MMscf dayy1 welly1. Horizontal CBM holes produce almost pure methane and typically have 1 year of production. q 1998 Elsevier Science B.V. All rights reserved.
Keywords: coalbed methane; production techniques; reservoir analysis; Appalachian Basin

1. Introduction This paper provides an overview of the production characteristics of Appalachian coalbed methane reservoirs and reviews the reservoir engineering techniques that are used for analysis of these reservoirs. The primary areas of production of Appalachian basin coalbed methane are directly associated with coal-mining activity. A variety of techniques are being used to recover coalbed methane from Appalachian basin reservoirs in and around active mine areas, especially in southwestern Virginia. Well types used include conventional ?vertical. coalbed methane wells, horizontal in-mine drainholes, gob wells, and wells drilled into abandoned mine areas ?sometimes called sealed gob wells.. There are also several areas throughout the basin where conventional vertical wells are being used to produce coalbed methane. This paper will review the production characteristics of several ongoing projects in the Appalachian basin and discuss the relative contributions of various development types on the observed production performance. Because of the variety of techniques used to recover Appalachian coalbed methane, the reservoir engineering analysis methods used to analyse and predict performance for these reservoirs are also more varied. Reservoir engineering studies typically focus on: ?1. understanding the reservoir mechanisms that control production, ?2. analysis of well production behavior, and ?3. prediction of future well andror reservoir performance. The information presented in this paper is based on past experiences in conducting reservoir studies for coalbed methane reservoirs in the northern and central Appalachian basins. This covers analyses of a wide range of project types, from fields utilizing vertical wells completed in multiple coalbeds to projects primarily associated with recovery of gas produced from mine operations. This paper focuses on the reservoir engineering techniques utilized for Appalachian coalbed methane reservoirs. A thorough overview of basic reservoir engineering techniques for coals can be found in Mavor et al. ?1996.. This reference and other literature should be consulted for specific equations andror methodologies for reservoir analysis of coalbed methane reservoirs.

2. Production characteristics of Appalachian coalbed methane projects This section provides a review of the production characteristics of Appalachian coalbed methane reservoirs. Production from Appalachian basin coalbeds covers a wide spectrum of well types and production techniques. Production from coalbed reservoirs in

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Fig. 1. Location of major Appalachian coalbed methane projects.

the Appalachian basin also covers a wide geographical area and a wide range of reservoir types. Production ranges from fields of vertical wells to mine-related projects. Fig. 1 shows the locations of major Appalachian coalbed methane projects. Table 1 provides a summary of the location, operator, and type of production for these projects as reported by Williams et al. ?1997.. Three of these projects ?two in the northern Appalachian basin and one in the central Appalachian basin. are non-mine-related projects, where vertical wells are used to access and produce coalbed gas from multiple,

Table 1 Summary of major Appalachian coalbed methane projects Project 1 2 3 4 5 Operator Belden and Blake BTI Energy Equitable Resources CONSOL Pocahontas Gas Partnership Location Indiana County, PA Fayette County, PA Nora Field, southwest VA Buchanon County, VA Buchanon County, VA Type Vertical wells Vertical wells Vertical wells Mine-related Mine-related

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thin, coalbeds. Two of the projects are mine-related projects, where a variety of production techniques are used to produce coalbed gas. These techniques include vertical wells drilled ahead of mining, horizontal in-mine boreholes, and gob production wells. The bulk of the current gas production from Appalachian coal projects is from the mine-related projects in southwestern Virginia. Vertical well projects in the northern Appalachian basin typically produce on the order of 1416 to 4247 m3 dayy1 welly1 ?50 to 150 Mscf dayy1 welly1 .. Conventional vertical well completions ?in non-minerelated projects. in the central Appalachian basin are slightly more productive, ranging from 2123 to 5663 m3 dayy1 welly1 ?75 to 200 Mscf dayy1 welly1 .. A major source of producible ?pipeline quality. coalbed gas in the Appalachian basin comes from gob well production. Gob wells in the mines in southwestern Virginia can produce in excess of 283 = 10 3 m3 dayy1 welly1 ?10 MMscf dayy1 welly1 . for short periods of time. The production of coal seam gas from Appalachian coalbed methane reservoirs can primarily be divided into two categories: non-mine-related production and mine-related production. The remainder of this section will discuss the key characteristics of each of these project types, the production techniques utilized for them, and will provide examples from Appalachian basin reservoirs of these project types. 2.1. Non-mine-related projects All projects in the Appalachian basin which have non-mine-related production from coalbeds utilize vertical wells. The key characteristics of these non-mine-related projects include the following: 1. Production is from multiple, thin coalbeds. 2. The completion interval is typically large ?61 to 305 m w200 to 1000 ftx.. 3. Relatively shallow depth ?152 to 762 m w500 to 2500 ftx.. 4. A large number of wells spaced on a regular pattern to promote interference ?well spacing ranging from ?24.3 to 40.5 ha w60 to 100 acrex per well.. The quality of Appalachian basin coals in which vertical well production may be economic ranges from high volatile to low volatile bituminous coal. Typical Appalachian vertical well projects have total net pay thicknesses ranging from 3 to 7.6 m ?10 to 25 ft., with as many as 15 individual coalbeds making up the total. Fig. 2 shows the generalized stratigraphic column as reported by Kelafant and Boyer ?1988. for the central Appalachian basins and indicates the major target coalbeds for coalbed methane development. The coalbeds of the New River and Pocahontas Formations are the primary completion targets in the central Appalachian basin. The Pocahontas No. 3 coalbed is the primary mined seam in the areas of major coalbed methane production in the central Appalachian basin. Because the completion targets for Appalachian vertical wells are generally multiple, thin coalbeds that are distributed over a relatively large gross interval, most Appalachian coalbed methane wells are completed as cased-hole completions. This facilitates limited entry or staged stimulation treatments. Light cements are generally used to minimize formation damage due to cementing, and staged cement operations may be utilized. Hydraulic fracture treatments performed on Appalachian vertical wells are generally

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Fig. 2. Generalized stratigraphic section for the central Appalachian basin and major target coal intervals.

designed to establish communication with all target coalbed intervals and provide a minimal degree of stimulation. This methodology is partially driven by cost considerations. Large volume stimulation treatments that would achieve a high degree of stimulation in all target coalbeds are not warranted economically for these types of wells. Therefore, low volume, limited entry or staged stimulation treatments are utilized. Fig. 3 shows an example of a cased-hole completion design for a vertical well in Belden and Blake’s Blacklick Creek project in Indiana County, PA, as presented by Belden and BlakerDevon Resources ?1994.. A typical stimulation treatment for wells in this field included three to four stimulation treatments to access six to eight coalbeds ?4 to 6.4 m w13–21 ftx net coal.. A typical stimulation stage used 151 m3 ?40,000 gal. of

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Fig. 3. Example of vertical well completion design for multiple zone completion strategy.

water and 11,340 kg ?25,000 lb. sand proppant pumped at 4.8 m3 miny1 ?30 barrels miny1 .. Clearly, the goal of the stimulation treatment was to achieve communication with all potential target coals. Because the productivity of these wells is relatively low ?less than 2830 m3 dayy1 welly1 w100 Mcf dayy1 welly1 x., cost was also a key consideration in completion design. This is typical of Appalachian projects in which vertical well development is used. Most Appalachian basin coalbeds are water-bearing. Therefore, pumps are necessary to lift water from the coalbeds. Ideally, the pumps are set below the lowest completed

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coal interval. To maximize gas desorption, the wells are produced at the minimum possible flowing bottomhole pressure. This generally means that either a field or well-specific compression is used to lower the bottomhole pressure to 69 to 138 kPa ?10 to 20 psia.. Water is disposed of using water disposal wells. Surface disposal of waters is generally not permitted in the Appalachian basin. One of the keys to economically producing coalbed gas from Appalachian basin reservoirs is minimizing operating costs. Therefore, water disposal costs may be a significant factor in the ability to economically produce Appalachian coalbed methane reservoirs. Most vertical wells completed in the central Appalachian basin produce relatively low volumes of water as compared to coalbed methane wells of the Black Warrior Basin and San Juan Basin. A typical well in the central Appalachian basin may produce 1.6 to 4.8 m3 dayy1 ?10 to 30 STB dayy1 . upon initial production, and decline to 0.2 to 0.3 m3 dayy1 ?1 to 2 barrels dayy1 . after 6 months of production. 2.2. Example non-mine-related project: Nora Field, southwestern Virginia The Nora Field in southwestern Virginia operated by Equitable Resources Exploration ?EREX. provides a good example of a producing field utilizing vertical wells in the Appalachian basin. Many of the characteristics of this project are typical of Appalachian coalbed methane projects utilizing vertical wells in non-mine-related areas. The Nora Field is located in part of four counties in southwest Virginia ?see Fig. 1.. More than 250 wells have been drilled by EREX in the Nora Field to date. These wells are drilled on 24 ha ?60 acre. per well spacing. The wells in the Nora Field are completed in the Lee Formation coalbeds. Typically, seven to 10 coalbeds are completed. Table 2 provides a summary of the typical parameters of Nora Field vertical wells. The average gas in place for Nora Field wells is estimated to be approximately 19,100 m3 welly1 ?675 MMscf welly1 .. Therefore, with typical vertical well recovery factor of approximately 30–60% of the initial gas in place, it would be expected that Nora Field wells would recover 5600 to 11,300 m3 welly1 ?200 to 400 MMscf welly1 . through their economic life, which is 30 years.

Table 2 Typical reservoir parameters: Nora Field vertical wells Parameter Formation Depth Reservoir pressure Net coal thickness Ash content Moisture content Adsorbed gas content, dry-ash free Well spacing Average gas in place a
a

Value ?range. Lee ?Greasy Creek–Pocahontas. 152–610 m ?500–2000 ft. 1379–5861 kPa ?200–850 psia. 2.4–6.1 m ?8–20 ft. 5–20% 0.5–2% ?200–600. scf tony1 24.3 ha ?60 ac welly1 . 19,100 m3 welly1 ?675 MMscf welly1 .

Using average parameters.

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Fig. 4. Average zero time production plot for 252 Nora Field coalbed methane wells.

Fig. 4 is an average well ?zero time. production profile for 252 wells in the Nora Field. This plot shows the average production profile from most of the wells in the field based on state-available information. On the basis of this plot, it can be seen that typical well in the Nora Field averages at approximately 0.3–0.5 m3 dayy1 ?2–3 STB dayy1 ., with a slowly declining water production rate trend. Gas production from the typical well in the Nora Field indicates a short period of inclining production, and then remains relatively flat or slightly declining. Peak production occurs after approximately 6 to 18 months of production. On the basis of these data, the average well in the Nora Field produces approximately 2350 m3 dayy1 ?83 Mscf dayy1 ., and recovers approximately 1.7–2.0 = 10 6 m3 ?60–70 MMscf. in the first 2 years of production. Wells in the Nora Field are completed using cased-hole completions similar to the example shown in Fig. 3. Each target coal zone is perforated. Well stimulation is accomplished through relatively small volume limited entry of fracture techniques using foam or water as the fracture fluid. Relatively small volume ?31,750 to 45,400 kg w70,000 to 100,000 lbx sand. are used to access the target coals. Typically, two to three stimulation stages are used in which two to four zones are stimulated within each stage. 2.3. Mine-related projects Projects that produce coalbed gas from mine-related activities are found in both the northern and central Appalachian basins as reported by Williams et al. ?1997., Kelafant and Boyer ?1988. and Kelafant et al. ?1988.. Most of these projects are associated with

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longwall mining operations. The characteristics of mine-related coalbed methane production are listed below. ?1. Production occurs from both the mined bed and the related coalbeds above and below the mined bed. ?2. Production may occur from a combination of well types. a. Vertical wells b. In-mine horizontal wells c. Gob production wells ?3. Mining scheduling and criteria may significantly impact production. Mines will operate with mine safety as a first priority and an economic return from gas production as a secondary priority. ?4. Mine development may significantly impact production characteristics. ?5. Costs will be shared by mine operation and gas development. Therefore, economic evaluation of only gas production operations may not be straightforward. A number of mine-related coalbed methane projects exist in the Appalachian basin where gas is recovered for sale or for use in generating power within the mine project. Gas may be gathered from vertical wells drilled ahead of the mine development, horizontal wells drilled within longwall panels or other mine workings to degassify the mined coalbed and associated coalbeds near the active mine workings, and from gob wells which degassify the zone behind the longwall in the area of relieved stress where gas outbursts can be substantial. The remainder of this section discusses the characteristics of each of these well types and presents examples of typical production from these wells. 2.3.1. Vertical wells The purpose of vertical wells in mine operations is primarily to degassify the coals ahead of mining. This includes degassification of the coalbed to be mined, as well as zones above and below the mine coalbed which might be affected by the relief of stresses caused by mining and may also produce gas that could potentially migrate into the mine workings. The life of these wells is generally limited by the mine development plan. At the point when the mine progresses through the location of a vertical well, the wells may be converted to gob production wells ?discussed later.. The life of a vertical well drilled ahead of mining is 3 to 5 years. Because a vertical well drilled in an active mine area may be mined through at some point, the design of these wells is significantly different than a vertical well in a non-mine area. At minimum, the wells are not cemented through the coalbeds to be mined. Wells are typically completed openhole or with a removable liner over the mined coalbed. Fig. 5 is a schematic of the completion typical of vertical wells drilled ahead of mine development. The well is completed such that it can easily be converted for gob production. The mine coalbed is typically not stimulated due to concerns over roof damage, but the other seams are perforated and fracture treated similar to vertical wells and non-mine-related areas. As in vertical wells in non-mine development areas, pumps are used to remove the water from these wells, and compression is used to minimize the producing pressure. The pumps are typically set at or below the mined coalbed to minimize the danger of the pump being stuck in the hole if significant coal fines or fill

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Fig. 5. Schematic of vertical well design of well planned for gob conversion.

occur in the openhole section. In some instances, removable liners are used to minimize these dangers and allow the pump to be set below the mined coalbed. 2.3.2. Horizontal drainholes Horizontal drainholes are used to degassify mine workings in and around the area of active mining. Fig. 6 shows the application of horizontal drainholes in longwall mining. These wells are generally utilized in the mine to target areas which cause problems to the mine activities ?inflows causing methane concentrations that are detrimental to mining.. Horizontal wells are used to drain the longwall panel in the coalbed to be mined. These wells are drilled using specialized underground drilling equipment. Wellbore diameters range from 2.5 to 10 cm ?1 in to 4 in.. and wells are typically 150 to 1500 m ?500 to 1500 ft. in length. The wells are completed openhole, with a short segment ?9 to 15 m w30 to 50 ftx. grouted to seal the end of the well near the mine workings. Production from the wells is gathered underground using a manifold system, and the production from many wells is combined into a single flow stream that is piped to the surface. Compression is generally utilized to maintain a slight vacuum on the production manifold and enhance the gas recovery capabilities of these wells. The life of horizontal drainholes is generally dependent upon the mine plan. Typically, 6 months to 1 year of production is realized from these wells. The production curves in Fig. 7 represent production from groups of horizontal drainholes drilled in longwall panels in an underground mine in the Appalachian basin. Because these wells are generally drilled near active mine workings that have been undergoing drainage

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Fig. 6. Example of horizontal boreholes for pre-drainage of longwall panels.

either from vertical wells or into the mine workings for a period of time, most horizontal wells do not experience significant water production. Therefore, the production profile from these wells is more typically a declining profile. The produced gas from these wells is generally pure methane, with little or no contamination from air due to the mine workings. Therefore, this gas is a prime target to be gathered and sold into a pipeline system.

Fig. 7. Example of horizontal well production from horizontal drainholes in longwall panels.

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2.3.3. Gob wells The purpose of gob wells is to degassify the zones behind the longwall operations in which stress has been relieved and a large quantities of gas are potentially released as described by Diamond et al. ?1993.. Fig. 8 shows a typical gob scenario and the area of relieved stress which occurs behind the longwall operation as illustrated by Patton et al. ?1995.. Once the mined coalbed is removed, the zones above and below the mined zone drop into the mine void. This causes an area of relieved stress around the mine that is related to the thickness of the mined zone and the dimensions of the longwall panel. Any gas that is contained in zones in this area of relieved stress will be released, as the permeability of these zones is dramatically increased. Gob wells are used to remove the large quantities of gas released in this process. The primary source of gob gas production is the gas contained in coalbeds above the mined coalbed. Generally, six to 12 gob wells are utilized per longwall panel, depending upon the panel dimensions and the quantities of gas expected to be produced. Casing is typically set at the top of the expected area of relieved stress, and the well is completed openhole to near the top of the mined coalbed from the lower point of the zone of expected relieved stress ?see Fig. 5.. Large fans are placed on gob wells to maintain a vacuum on the wells, such that they operate at the minimum possible flowing pressure. An example of gob well production from a series of gob wells and a longwall panel is shown in Fig. 9. Note that the typical characteristic of these wells is very high volumes of production ?as much as 0.3 to 0.4 = 10 6 m3 dayy1 w10 to 15 MMscf dayy1 welly1 x. immediately after the mine passes below each well. This coincides with the timing of the release of stress in the strata in which production occurs. Gob production may exhibit variable produced gas quality. In the early stages of production, the gas quality is primarily methane and there is very little contamination of

Fig. 8. Schematic of fracturing zones caused by longwall mining.

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Fig. 9. Example of gob well production from a longwall panel.

air. Later in life, gob production may significantly be a mixture of methane and air, which is drawn in from the active mine workings. The quality of produced gas from gob wells can be controlled somewhat by varying the compression on the well to correspond with the profile of expected methane release. Larger compression is used early in gob production cycle when methane release volumes from the reservoir are high and less compression is needed later when methane release is stabilized at a lower level. At all times, however, the methane concentration in the mine is used as a controlling factor for controlling the compression on gob wells. Mine safety is always considered to be the first priority. However, in cases where the compression of gob wells is actively controlled, produced gas quality can remain high for long periods of time and a large percentage of saleable gas can be recovered.

3. Reservoir analysis techniques This section discusses the reservoir engineering techniques used for evaluating Appalachian methane coalbed reservoirs. One of the key elements of reservoir analysis is estimating the in-place coalbed gas resource. Once the volume of resource in place is established, the recoverability of the resource is studied and predicted using reservoir analysis methodologies. General techniques for analyzing coal seam reservoirs have been presented in Mavor et al. ?1996.. This section will focus on the application of these techniques to Appalachian coalbed properties. General reservoir analysis methodologies include: ?1. estimating the gas in place for the coal reservoir, ?2. estimating permeability and deliverability of the coalbed methane

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reservoir, and ?3. performing production data analysis and forecasting future production for the coalbed methane reservoir. One of the key factors in conducting reservoir engineering studies is the availability and quality of data required for these studies. Key data used in reservoir engineering studies include measurements of key reservoir properties ?such as gas content, isotherms, and coal quality., well logs, production data, and well-completion information. Considerable effort may be spent collecting the data required to conduct proper reservoir engineering studies for coalbed methane reservoirs. Another requirement for conducting reservoir studies for coalbed methane reservoirs is the availability of proper tools required for analysis. For analyzing well tests conducted on coalbed methane reservoirs, standard well-test analysis tools utilized for conventional oil and gas reservoirs may generally be utilized. However, to evaluate production data and forecast future production for coalbed methane reservoirs, a reservoir simulator, which incorporates the mechanisms that control coalbed gas and water flow, must be used. A number of simulators are available commercially for this purpose and have been discussed in detail by King and Ertekin ?1989a,b, 1994.. 3.1. Estimating gas in place Eq. ?1. shows the generalized volumetric gas in place equation for estimating gas in place for coalbed methane reservoirs as reported by Mavor et al. ?1996.. The key parameters in developing an accurate estimate of gas in place are: ?1. the adsorbed gas content, ?2. the ash content, and ?3. the moisture content of the target coalbed. These parameters are obtained through direct measurement from coal, core, or cuttings samples. A thorough discussion of the methodologies used to estimate these parameters is found in Mavor et al. ?1996.. G i s Ah 43,560u f ? 1 y S wfi . Bgi q 1.359Cgi rc ? 1 y fa y f m .

? 1.

Where: G i s gas in place at initial reservoir conditions, Mscf; A s drainage area, ac; h s coal thickness, ft; f f s interconnected fracture ?effective. porosity, fraction; S wfi s interconnected fracture water saturation, fraction; Bgi s gas formation volume factor at p I , rcf Mscfy1 ; Cgi s initial sorbed gas concentration, scf tony1 dry, ash-free coal; rc s coal density, g cmy3 ; fa s average weight fraction of ash, fraction; f m s average weight fraction of moisture, fraction; 43,560 s Conversion factor, ft 2 acy1 ; 1.359 s conversion factor,

? Mscf. ? ton. ? cm3 . . ? ac y ft . ? scf . ? gm.
The main difficulty in estimating gas in place for Appalachian coalbed methane reservoirs is that the target coalbeds are made up of multiple, thin coal stringers spread out over a large stratigraphic interval. Furthermore, many coalbed methane projects are economically marginal, so it is difficult to justify spending large amounts of money in obtaining reservoir data. For example, in the Nora Field in Virginia, it would be necessary to obtain core samples and conduct core tests on at least 12 different coal

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zones to obtain an accurate estimate of gas in place. This quantity of test analysis is often prohibitive in terms of the cost. Typically, gas in place estimates for Appalachian coalbed methane reservoirs are based on a sampling of adsorbed gas content measurements and desorption isotherm tests for key target coalbed intervals. The desorption isotherms are then utilized to estimate gas in place ?as a function of estimated reservoir pressure. for other target coalbeds in which measurements are not available. Density logs can also be very useful for extrapolating gas content and basic coal property information from zone to zone. However, density logs are not run in many Appalachian coalbed wells. One aspect of mine-related projects that is advantageous to coalbed methane reservoir evaluation is the availability of a large quantity of core data. In mining projects, many coreholes are drilled throughout the area expected to be mined to define the structure and quality of the target coalbeds. This often provides a highly detailed description of the coalbeds within and around the mine area. These data are often extremely useful in reservoir analysis. Table 3 shows the key factors in estimating gas in place and mine-related projects. For vertical wells, conventional methods for estimating gas in place for coalbed methane reservoirs are applicable. For horizontal wells, the key factor is determining which zones are targeted by the horizontal wells, and including only those zones in the analysis. In longwall mining operations, this is generally the thickness of the mined interval. The area of the zones targeted to be drained by the horizontal wells may also be determined by the mine operations. For example, in longwall mining the area of the longwall panel is the target for drainage. In gob well analysis, the estimation of gas in place is more difficult to obtain. The first difficulty is estimating which zones will be included in the area of relieved stress and will therefore contribute to production. A second consideration is estimating the area which will be drained by each gob well. Diamond et al. ?1993. and Patton et al. ?1995. have reported that the location of the mine panel within the mine development plan has a significant impact on overall gob production. This is because production into the gob can migrate from large distances when the mine workings are adjacent to a virgin coalbed methane reservoir, as opposed to old or abandoned mine workings. In addition, difficulty in estimating gas in place in the gob often results because relatively poor data are available for zones in the gob above and below the mined zone. Most reservoir testing for the mining operation concentrates on the parameters relating to the mined coalbed. Experience suggests that estimates of gas in place for gob wells are underesti-

Table 3 Key factors in gas in place estimates for mine-related projects Well type Vertical Horizontal Gob Thickness Completed coals Completed coals All gas-bearing strata in zone of relaxed stress Area Determined by well spacing Determined by well spacing or mine workings Estimated extent of relaxed stress zone Reservoir Permeable coals Permeable coals All gas-bearing strata

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mated relative to the production realized by the gob wells by a factor of two or more. One key contributing factor to this underestimation of gas in place is the fact that any zone containing gas within the gob will be productive after their relief of stress. The increase in permeability in these zones is such that they will be productive after the relief of stress. Therefore, zones would be considered too low quality as to be productive under normal permeability conditions and contribute gas to the gob wells. Detailed studies undertaken by the U.S. Bureau of Mines and reported by Diamond et al. ?1993. and Patton et al. ?1995. for example, have shown that when care is taken in estimating the gas content of all zones believed to be in the gob, accurate estimates of gas in place for gob wells can be achieved. 3.2. Estimating permeability and deli?erability Permeability is often the key factor in determining the producibility of coalbed methane reservoirs. For this reason, it is desirable to conduct well tests to determine coalbed permeability. For Appalachian basin coals, relatively simple, low-cost tests are desired. This would include the slug test, or tank test ?which is a form of injection fall per off test. which are described by Saulsberry et al. ?1994, 1995.. Fig. 10 shows the setup for a typical tank test. As can be seen from the schematic, the equipment required

Fig. 10. Example of tank test setup for testing permeability of shallow coal zones.

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to conduct such a test is relatively simple and inexpensive to operate. The problem of having to test multiple potential pay targets is also an impediment to conducting well tests in Appalachian coalbed methane reservoirs. Typically, only key target intervals are tested to determine permeability. It may be necessary to design specialized completion procedures, such that these zones can be tested in isolation. Another important issue in testing Appalachian coalbed methane wells is determining which zones are contributing to production. For this purpose, a zone isolation test or production log is required. The procedure used to perform an isolation test using a zone isolation packer was described by Saulsberry et al. ?1994.. This technique or a production logging method should be utilized to determine which zones are contributing to production. When thin, multiple zones are completed using limited entry techniques, it is highly possible that only a fraction of the target zones are contributing to production. In this case, reservoir analyses that assume that all zones are open to production will overpredict future coalbed methane production and reserves. 3.3. Production data analysis Production data analysis is a key tool to utilize for analysing past reservoir performance and predicting future performance. Coalbed methane simulators are used for this purpose. Such simulators are useful in estimating production from all types of wells, including vertical wells, horizontal drainholes, and gob wells. Accurate estimates of key reservoir data are essential to utilizing coal seam reservoirs for estimating production from Appalachian coal wells and projects. This includes the parameters required to estimate gas in place, as well as, parameters controlling well deliverability ?such as permeability.. History matching observed production performance is useful for estimating key parameters such as permeability, porosity, initial water saturation, and the degree of well stimulation. However, accurate measurements of key baseline parameters such as net thickness, gas in place, and desorption isotherm are required for using the simulators to accurately predict well behavior. The accuracy of the results of any engineering study is strongly dependent upon the quality of data used in the study. This is especially true of predictions of future production from wells or groups of wells. Therefore, the reservoir engineer should spend considerable time critiquing the quality of data made available for a study. Furthermore, every effort should be made ?within the bounds of reasonable cost. to obtain high quality data that can be used in reservoir engineering studies. This generally includes gathering of cores for gas content, isotherm, measurements, as well as, well specific production information. Typically, well tests are also conducted on key target coal seams to attempt to estimate permeability, which is a key controller of coalbed producibility. Experience has found that coalbed reservoir simulators are useful for analysing and predicting behavior of vertical wells and in-mine horizontal drainholes. Several good papers have been published that explain the use of such simulators for this purpose ?see King and Ertekin, 1994.. The analysis of gob well production, however, has proved to be somewhat more empirical in nature. Gob well production is strongly impacted by the duration and timing of coal-mine development, as well as the rock mechanics of the

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M.D. Zuberr International Journal of Coal Geology 38 (1998) 27–45

characteristics of the strata above and below the mined zone. Because these parameters are not directly accounted for by coalbed methane simulators, these cannot be directly used to estimate gob gas production.

4. Summary Coalbed methane production from Appalachian basin reservoirs has reached significant levels of maturity in some areas. There are currently both mine-related projects and non-mine-related projects that are achieving economic production from the northern and central Appalachian Basins. Key projects include the Nora Field of Virginia in which non-mine-related production is realized from vertical development wells, and the projects operated by CONSOL and Pocahontas Gas Partnership which produce significant coal-mine-related methane from the mine developments in southwestern Virginia. There are numerous smaller scale developments of both mine-related and non-mine-related projects currently being developed or tested throughout the Appalachian basin. One key factor in the development of vertical well production from Appalachian coalbed methane reservoirs is that the target zones are multiple, thin zones spread out over a relatively large stratigraphic interval. This requires staged or limited entry completion techniques that access all potential target zones. Relatively low production rates and reserves are characteristic of Appalachian vertical coalbed well projects. Therefore, minimizing development and operation costs for these projects are keys to economic success. Mine-related production is the most prolific form of coalbed methane production in the Appalachian basin. The bulk of mine-related production is realized from gob wells; however, significant production is achieved from pre-mined vertical wells and in-mine horizontal boreholes. Gob well production is driven by the relief of stress in zones above and below the mined zone which occur due to longwall mining operations. This relief of stress causes increased permeability in gas-bearing zones above and below the mined zone and rapid release of large quantities of gas. Experience with projects in southwestern Virginia and other locations throughout the United States has shown that this gas can be gathered and produced in economic quantities.

References
Belden and BlakerDevon Resources, 1994. Blacklick coalbed methane project update. Presentation at the North American Coalbed Methane Forum, Morgantown, WV. Diamond, W.P., Jeran, P.W., Trevits, M.A., 1993. An analysis of production trends and the potential for increasing gas flow from longwall gob gas vent holes. The 1993 International Coalbed Methane Symposium College of Continuing StudiesrPMDP. The University of Alabama, Tuscaloosa, pp. 443–452. Kelafant, J.R., Boyer, C.M., 1988. A Geologic Assessment of Natural Gas From Coal Seams in the Central Appalachian Basin. Gas Research Institute, Chicago, 66 pp. Kelafant, J.R., Wicks, D.E., Kuuskra, V.A., 1988. A Geologic Assessment of Natural Gas From Coal Seams in the Northern Appalachian Basin. Gas Research Institute, Chicago, 81 pp.

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King, G.R., Ertekin, T.M., 1989a. A survey of mathematical models related to methane production from coal seams: I. Empirical and equilibrium sorption models. The International Coalbed Methane Symposium. College of Continuing StudiesrSOMED, The University of AlabamarTuscaloosa, pp. 125–138. King, G.R., Ertekin, T.M., 1989b. A survey of mathematical models related to methane production from coal seams: II. non-equilibrium sorption models. The International Coalbed Methane Symposium. College of Continuing StudiesrSOMED, The University of AlabamarTuscaloosa, pp. 139–155. King, G.R., Ertekin, T.M., 1994. A survey of mathematical models related to methane production from coal seams: III. Recent developments ?1989–1993.. The International Coalbed Methane Extraction Conference, London, UK. Mavor, M.J., Paul, G.W., Saulsberry, J.L., Schafter, P.S., Schraufnagel, R.S., Steidl, P.F., Sparks, D.P., Zuber, M.D., 1996. A Guide to Coalbed Methane Reservoir Engineering. Gas Research Institute, Chicago, 308 pp. Patton, S., Jiang, Y., Deb, D., Novak, T., Park, D., 1995. Role of longwall gob formation in coalbed methane Emission. The International Unconventional Gas Symposium. College of Continuing Studies, PMDP, The University of Alabama, Tuscaloosa, pp. 151–162. Saulsberry, J.L., Spafford, S.D., Steidl, P.F., Litzinger, L.A., Durden, A.H., Rochester, C.L., Kuuskraa, V.A., Young, G.B.C., 1994. Effective completions for shallow coal seams. Gas Research Institute Topical Report No. GRI-93r0366, Chicago, 76 pp. Saulsberry, J.L., Lambert, S.W., Wallace, J.A., Spafford, S.D., Steidl, P.F., 1995. Rock Creek multiple coal seams project final report. Gas Research Institute Report No. GRI-05r0036, Chicago, 109 pp. Williams, J.C., Schwochow, S., Hampton, G., 1997. The International Coal Seam Gas Report. Cairn Point Publishing, Denver, 218 pp.


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