MRCSP Phase II Topical Report October 2005 October Authors. Kentucky Geological Survey 2

Transcription

1 Storing and Using CO 2 for Enhanced Coalbed Methane Recovery in Unmineable Coal Beds of the Northern Appalachian Basin and Parts of the Central Appalachian Basin MRCSP Phase II Topical Report October 2005 October 2010 Authors Stephen F. Greb, 1 Cortland F. Eble, 1 Ernie R. Slucher, 2 Kristin M. Carter, 3 Katharine Lee Avary 4 1 Kentucky Geological Survey 2 Ohio Department of Natural Resources, Division of Geological Survey 3 Pennsylvania Department of Conservation and Natural Resources, Bureau of Topographic & Geological Survey 4 West Virginia Geological and Economic Survey DOE Cooperative Agreement No. DE-FC26-05NT42589 OCDO Grant Agreement No. DC-05-13

2 NOTICE This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government, nor any agency thereof, nor any of their employees, nor Battelle, nor any member of the Midwest Regional Carbon Sequestration Partnership (MRCSP) makes any warranty, express or implied, or assumes any liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendations, or favoring by Battelle, members of the MRCSP, the United States Government or any agency thereof. The views and the opinions of authors expressed herein do not necessarily state or reflect those of the members of the MRCSP, the United States Government or any agency thereof.

3 Storing and Using CO 2 for Enhanced Coalbed Methane Recovery in Unmineable Coal Beds of the Northern Appalachian Basin and Parts of the Central Appalachian Basin by Stephen F. Greb 1, Cortland F. Eble 1, Ernie R. Slucher 2, Kristin M. Carter 3, Katharine Lee Avary 4 1 Kentucky Geological Survey, University of Kentucky, Lexington, KY Ohio Department of Natural Resources, Division of the Geological Survey, Columbus, OH Pennsylvania Department of Conservation and Natural Resources, Bureau of Topographic & Geologic Survey, Pittsburgh, PA West Virginia Geological and Economical Survey, Morgantown, WV 26508

4 ABSTRACT Unmineable coal beds are one of several potential reservoirs being investigated for geologic carbon sequestration (storage) in the United States. Unmineable coal beds are attractive targets for sequestration because carbon dioxide (CO 2 ) could be used for enhanced coalbed methane recovery (ECBM), which would generate value-added revenue for CO 2 storage. In the Midwest Regional Carbon Sequestration Partnership (MRCSP) region, unmineable coals currently producing coalbed methane (CBM) at depths of more than 1,000 feet occur in the northern Appalachian (Dunkard) basin and the southern Appalachian (Pocahontas) basin. These are the areas in which ECBM with CO 2 would likely take place in the MRCSP region. Many large CO 2 point sources are within, or near to, the northern Appalachian basin CBM fields. The MRCSP lacked a Phase II coal sequestration demonstration project, mainly because a separate U.S. Department of Energy (DOE)-co-sponsored demonstration of this technology was already planned in northern West Virginia. In lieu of a demonstration test project, this report summarizes: (1) current research regarding the use of CO 2 for ECBM in the MRCSP region that was not addressed in the Phase I report; and (2) CO 2 injection tests in coals from non-mrcsp projects in the region, which are then discussed relative to the potential use of CO 2 for ECBM in the northern Appalachian basin and the MRCSP-portion of the central Appalachian basin. This report does not address those areas of the MRCSP region where CBM production has not been realized. i

5 CONTENTS Abstract...i List of Figures and Tables.iii Acronyms Used in This Report iv Executive Summary...v Introduction...1 Unmineable Coal Beds...2 Adsorption on Coals...4 Coal Porosity and Permeability...4 Producing Methane from Coals...5 Existing CBM Fields in the MRCSP Region...6 Dunkard Basin CBM...7 Dunkard Basin CBM and CO 2 Sources. 10 Pocahontas Basin CBM. 12 Pocahontas Basin CBM and CO 2 Sources. 14 Enhanced Coalbed Methane Recovery...15 Optimal Characteristics for ECBM with CO Coal Swelling...18 Other CO 2 -Induced Physical Changes to Coal...20 Compositional Controls on CO 2 Sorption...20 Potential Environmental Issues...21 CO 2 Field Tests in the Region...22 Northern Appalachian Basin Field Test...22 Central Appalachian Basin Field Test...24 Illinois Basin Field Test...24 Discussion...25 Potential CO 2 Storage and ECBM Recovery...26 Summary and Conclusions...27 References...29 Appendix...40 ii

6 FIGURES Figure 1. Net thickness of Pennsylvanian coals at least 500-ft below drainage...3 Figure 2. Northern Appalachian basin CBM fields and region...7 Figure 3. Pennsylvanian coal beds, associated strata, and CBM producers in the northern Appalachian basin of Pennsylvania and northern West Virginia...9 Figure 4. Point sources of CO 2 emissions relative to the CBM wells in the Dunkard basin...11 Figure 5. Central Appalachian basin major CBM fields...12 Figure 6. Pennsylvanian coal beds, associated strata, and CBM producers in the central Appalachian basin of southwestern Virginia, southern West Virginia, and southeastern Kentucky...13 Figure 7. Point sources of CO 2 emissions relative to the CBM wells in the MRCSP parts of the Pocahontas basin...15 TABLES Table 1. Estimated CO 2 storage capacity by state...2 iii

7 Acronyms Used in This Report Bcf billion cubic feet CBM coalbed methane CH 4 methane CO 2 carbon dioxide DOE United States Department of Energy DEP Department of Environmental Protection ft foot Mcf thousand cubic feet Mcf/d thousand cubic feet per day MGSC Midwest Geological Sequestration Consortium md - millidarcy MRCSP Midwest Regional Carbon Sequestration Partnership N 2 nitrogen scf/t standard cubic foot per short ton SECARB - Southeast Regional Carbon Sequestration Partnership Tcf trillion cubic feet iv

8 EXECUTIVE SUMMARY Unmineable coal beds are one of several potential reservoirs being investigated for geologic carbon sequestration. Storing CO 2 in unmineable coal beds is attractive because CO 2 should displace coalbed methane (CBM), which then can be recovered to generate revenue with CO 2 storage. Two CO 2 injection tests in coalbeds are underway in the Appalachian basin. CONSOL Energy, Inc. is testing the Middle Pennsylvanian Upper Freeport coal in the Dunkard basin part of the northern Appalachian basin, which is located in the Midwest Regional Carbon Sequestration Partnership (MRCSP) region, but managed as a separate project from the MRCSP. The Southeast Regional Carbon Sequestration Partnership (SECARB) has tested Lower Pennsylvanian coals in the southern Appalachian (Pocahontas) basin, just south of the MRCSP region. A coal test was also recently completed in the Illinois basin by the Midwest Geological Sequestration Consortium (MGSC), and a coal test is planned for the southern Appalachian basin by SECARB. Results from these tests are pending and will help to determine the feasibility of using this technology in the MRCSP region and in the eastern United States. Future use of CO 2 for ECBM would likely take place in existing CBM fields. Many large CO 2 point sources are within or near to the northern Appalachian (Dunkard) basin coal fields. Fewer point sources are as close to the MRCSP part of the central Appalachian (Pocahontas) basin coal fields. Previous research indicates substantial remaining CBM resources in both areas, so potential exists for use of this technology in the MRCSP region. Several questions remain regarding the feasibility of this technology, however. Existing research indicates coal swelling and other possible physical changes to coal during injection may complicate or even limit injectivity of CO 2 in coal beds. More research is needed on coal composition, permeability, swelling, and any other potential physical changes in coal caused by CO 2 for the likely target coal beds in both CBM producing areas in the region. Potential environmental impacts of injecting CO 2 in previously hydrofracked coal beds should also be investigated, but are likely to be similar to existing impacts from CBM production. Collection of permeability data for shales above target coal beds would be useful for ensuring confining intervals to limit potential gas and fluid migration out of zone. v

9 It is anticipated that data from ongoing field tests and further laboratory research can be used to develop standardized methods for exploration, analyses, injection, and monitoring of CO 2 for ECBM in the MRCSP region. Engineering and well-design data and research on possibilities of mixed gas injection to limit swelling, and other drilling and treatment factors are needed in order to determine best practices for drilling, injection, and recovery. Monitoring technologies also need to be tested to determine which work best for tracking CO 2 injected into coal beds so that protocols and guidelines can be developed for long-term monitoring and verification. vi

10

11 INTRODUCTION This report summarizes: (1) current research regarding the use of CO 2 for ECBM in the MRCSP region that was not addressed in the Phase I report; and (2) CO 2 tests in coals from non- MRCSP projects in the region, which are then discussed relative to the potential use of CO 2 for ECBM in the northern Appalachian (Dunkard) basin and the MRCSP-portion of the central Appalachian (Pocahontas) basin. This report does not address those areas of the MRCSP region where coalbed methane (CBM) production has not been realized. In the Phase I MRCSP report (Wickstrom and others, 2005), the stratigraphy and structure of coal-bearing strata in the Michigan basin, northern Appalachian basin, and MRCSPportion of the central Appalachian basin were summarized. Regional assessments of coal thickness at depth in combination with estimated CBM resources were used to estimate the gross storage capacity of CO 2 in coal (Table 1). Phase I MRCSP research demonstrated the relative potential for using coal beds for CO 2 storage in the region and the approximate geographic area where coal beds more than 500 feet (ft) below drainage and at least 12 inches thick occur in the basin. Since this initial phase of work, most of the emphasis on using coal beds for carbon storage has shifted to using coals only where they are producing CBM as part of ECBM projects. This is a significant shift in thought, as the areas in which there is current CBM production in the Appalachian basin are significantly smaller in size than the area in which coals are situated more than 500 ft below drainage (i.e., one of the limits on coal beds considered for the storage capacities presented in Table 1). 1

12 Table 1. Estimated CO 2 storage capacity by state based upon the estimated area of cumulative thickness of coal beds at least 1 ft thick and greater than 500 ft deep. Data from Wickstrom and others (2005), Table 11, p. 43. mi 2 =miles squared, BT=billion U.S. short tons [1BT=0.907 gigatonnes (Gt, billion metric tons)]. CO 2 Storage Capacity (BT) State Coal Area (mi 2 ) Total 10% Eastern Kentucky 3, Ohio 5, Pennsylvania 4, West Virginia 12, Total 25, Unmineable Coal Beds Unmineable coal beds are one of several potential reservoirs being investigated for geologic carbon sequestration (storage). The U.S. Department of Energy (DOE)(2008) considers unmineable coals as attractive storage reservoirs for several reasons: 1) The United States has the largest coal resources in the world and coal fields are widely distributed across the country. 2) Carbon dioxide can be used for ECBM recovery, and the revenue from the additional natural gas produced could offset some of the costs of CO 2 injection; 3) Injected CO 2 is adsorbed onto the coal, and as such adheres to the coal with little risk that it will leak to the surface through time; and 4) Many coal-fired power plants are located in coal fields where deep unmineable coal may be accessible. The definition of unmineable is mainly an economic decision and varies from company to company. During Phase I, the MRCSP used a 500-ft minimum depth (i.e., below drainage depth) limit for determining CO 2 storage capacity in coal beds. This depth is below most current underground-mining levels and below the level of surface fracturing and connectivity to the surface (Wickstrom and others, 2005). Figure 1 is a net-coal thickness map for part of the region using the 500-ft depth limit and a one-foot minimum thickness for individual coals used to 2

13 Figure 1. Net thickness of Pennsylvanian coals at least 500-ft below drainage and one-ft or greater in thickness in part of the MRCSP region (modified from Wickstrom and others, 2005, Figure A15-3.). Coals in the southern part of West Virginia were not assessed. calculate the net-coal thickness within the coal-bearing interval. Other regional partnerships used a more conservative value of 1,000 ft beneath the surface (or beneath drainage in areas of topographic relief) to define unmineable coals. More restrictive definitions are doubtless tenable (e.g., coal beds not presently being mined at shallower depths or which could not be utilized for future in situ gasification). Relative to the Phase I results shown in Table 1, a 1,000-ft depth would significantly decrease the total available area and storage capacity. For example, in Kentucky, the area where coals exist at more than 1,000 ft below drainage would be restricted to 3

14 two small areas. Likewise, in Ohio, the area in which coals would be more than 1,000 ft below drainage would be negligible. Adsorption on Coals One of the main reasons deep coals are being investigated as sequestration reservoirs for CO 2 is that CO 2 has a greater affinity for coal than methane. This means that injected CO 2 should displace methane (CH 4 ) that adheres to or is adsorbed to the coal matrix. The adsorption mechanism also means that injected CO 2 should adhere to the coal matrix, effectively sealing it within the coal bed and limiting the potential for large-scale leakage into overlying units and ultimately the surface. Adsorption ability varies with gas type, rank, coal type, and moisture content (Yee and others, 1993; Clarkson and Bustin, 1996; Bustin and Clarkson, 1998). Ratios of CO 2 /CH 4 are commonly reported as 2:1 for bituminous coals (Byrer and Guthrie, 1999; Gentzis, 2000; White and others, 2005), although CO 2 /CH 4 ratios of 3.5 to 5.3 were reported for Illinois basin bituminous coals (Mastalerz and others, 2004), which have similar ranks and depths to the gas-producing coals in the northern Appalachian basin. Ratios may exceed 10:1 in lignites (Stanton and others, 2001; Burruss, 2003; Reeves, 2003a; Shi and Durucan, 2008), but low-rank coals do not occur in the MRCSP study area. Coal Porosity and Permeability Coalbed methane is dispersed in coal microporosity (pores less than 20 angstroms diameter), mesoporosity (pores angstroms diameter), and macroporosity (pores more than 500 angstroms diameter) (King and others, 1986; White and others, 2005). Microporosity (less than 20 angstroms) is found in the coal matrix and can be considered the matrix porosity. Microporosity accounts for most of the porosity in coal and is the principle control of the sorption of CBM in coal (Gray, 1987; Mavor and Nelson, 1997; Shi and Durucan, 2005; White and others, 2005). It will also be a significant control on CO 2 adsorption onto coal. Microporosity may be partly controlled by coal composition, with micropore capacity increasing 4

15 in vitrinite-rich coals and decreasing in coals with high ash yields (Clarkson and Bustin, 1996; Bustin and Clarkson, 1998). Coal porosity and permeability are also influenced by natural coal fractures called cleats. Mesopores and macropores are associated with cleating. Most coals exhibit two cleat orientations. The dominant cleat orientation is the face cleat. Face cleats are continuous fractures in coals and are oriented perpendicular to bedding. Butt cleats are subordinate cleats that form at near right angles to the face cleat and are discontinuous in coals, generally ending at a face cleat (McCulloch and others, 1974; Diamond and others, 1988; Laubach and others, 1998; Close, 1993). Butt cleats are pathways of diffusion of gas from the micropores of the coal matrix to the face cleats. Once methane has entered the cleat system, face cleats control the permeability, and therefore the flow of gas to and from the well bore (Mavor and Nelson, 1997; Gentzis, 2000; Shi and Durucan, 2005; White and others, 2005). Permeability in coals is generally low (less than 30 millidarcies [md]) and related to cleat spacing and effective stress or hydrostatic confining pressure, which changes with desorption and adsorption of gases (Gray, 1992; Close, 1993; Laubach and others, 1998; Shi and Durucan, 2005; White and others, 2005; Gorucu and others, 2007). Cleat spacing and permeability are influenced by a variety of factors including rank, lithotype, ash yield, and mineralization (Law, 1993; Laubach and others, 1998; Pitman and others, 2003). Cleat direction, spacing, and knowledge of mineralization in target coal beds are critical data for successful CBM production. Cleat data will also be critical to ECBM with carbon storage. Producing Methane from Coals Primary recovery of CBM from a coal reservoir occurs by releasing the confining pressure on the coal reservoir. In conventional CBM production, pressure is generally released through the dewatering the coal. As water is produced, the hydrostatic pressure in the coal is lowered, and methane is desorbed from micropores in the coal matrix to the butt and face cleats (Gray, 1982; King and others, 1986; Shi and Durucan, 2005; White and others, 2005). As gas 5

16 flows from the reservoir, the coal matrix shrinks with concomitant opening of cleats, which increases the permeability and conductivity of the coal, resulting in increased methane flow to the producing well. Unfortunately, injection of CO 2 results in the opposite physical changes, and CO 2 causes more swelling than the original CH 4 that was in the coal (Pekot and Reeves, 2002). As much as 50 percent of the original gas in place may remain in a coal bed after primary production (Gentiz, 2000). Primary recovery depends on coal rank, thickness, desorption rate, cleat orientation, permeability, porosity, water saturation, and other factors (Gray, 1982; Gentiz, 2000). Annual CBM production in West Virginia and Pennsylvania is more than 27 billion cubic feet (Bcf) and cumulative production exceeds 159 Bcf. If similar amounts of methane remain in the coals, than there is significant economic benefit for ECBM with CO 2 in the region. EXISTING CBM FIELDS IN THE MRCSP REGION MRCSP Phase I mapping showed three regions of thick coal at depth (Fig. 1). The trend of thick net coal in northern West Virginia and southwestern Pennsylvania is part of a sub-basin of the northern Appalachian referred to as the Dunkard basin. The southern region is part of the central Appalachian basin. The coals at depth in southern West Virginia are similar to the coals at depth in neighboring southwestern Virginia, in a part of the central Appalachian basin called the Pocahontas basin. In southeastern Kentucky, the mined coals are slightly younger than the coals in southern West Virginia and southwestern Virginia. To date there has been no CBM production in Maryland or Ohio. Seventeen CBM wells have been drilled in southeastern Kentucky. These wells produced from multiple thin coals (each less than three ft thick) in the Breathitt Group, mostly from the Lower Pennsylvanian Grundy Formation. Wells are ft deep, and the majority of coals were less than 1,000 ft deep. No wells are currently producing. Ongoing research as part of the Southeast Regional Carbon Sequestration Partnership (SECARB) s Phase II project is examining the potential of southeastern Kentucky for future ECBM with CO 2, and Eble and others (2009) have recently summarized results from an exploration well. Even so, the lack of current CBM production 6

17 means there is nothing to enhance at the present time, so this portion of the MRCSP region is not discussed further herein. Dunkard Basin CBM The southwestern Pennsylvania-West Virginia panhandle area has several thick coals at depth which together result in cumulative coal thicknesses in excess of 30 ft at depths of more than 500 ft (Fig. 1). The Dunkard basin is also an active CBM play (Bruner and others, 1995; Markowski, 1998, 2001; Milici, 2004; Avary, 2008). Figure 2 shows the distribution of CBM fields in the Dunkard basin and the region of potential CBM defined by the minimum petroleum system of Milici (2004). The orange line in Figure 2 is the approximate boundary of rank that would produce thermogenic methane (vitrinite reflectance, Ro > 0.8). In 2002, 252 wells were Figure 2. Northern Appalachian basin CBM fields and region (from Milici, 2004, Figure 10). 7

18 producing 1.4 Bcf of CBM in Pennsylvania and northern West Virginia (Milici, 2004). West Virginia s CBM development has dramatically increased in the last few years to 9.2 Bcf in Coal seams currently being targeted for CBM production are found in the Allegheny Formation, and include the Upper, Middle, and Lower Kittanning and Lower and Upper Freeport coal beds (Fig. 3). The Lower Kittanning coal has low-volatile bituminous to high-volatile C bituminous rank and is a medium ash, medium- to high-sulfur coal. In the southwestern corner of Pennsylvania and adjacent areas of West Virginia, where it is at its greatest depth, it has highvolatile A bituminous rank (Milici and others, 2000). The Upper Freeport coal has medium- to high-volatile bituminous rank, and is a medium- to high-ash, medium- to high-sulfur content coal (see summary of coal quality data in Appendix). In the southwestern corner of Pennsylvania and adjacent areas of West Virginia, where it is at its greatest depth, the coal has high-volatile A bituminous rank (Ruppert and others, 2000). The majority of the CBM in West Virginia is currently being produced from the Pittsburgh coal, which is the basal unit of the Pittsburgh Formation, Monongahela Group (Fig. 3). More coal is mined from the Pittsburgh than any other seam in the eastern United States (Tewalt and others, 2000) and many CBM wells are drilled to degas the coal in advance of mining. The producing coals of the Dunkard basin decrease in thickness toward the south in West Virginia and the west into Ohio. They do not extend into the central Appalachian basin. Most CBM exploration in the Dunkard basin targets synclinal areas where a majority of the target coals can be preserved at greater depth. Coal cleats trend perpendicular and parallel to syncline axes (McCulloch and others, 1974). Traditionally, most CBM wells were vertical wells, but many of the newer wells are multi-lateral horizontal wells with three or four legs. Higher productivity is obtained in horizontal wells drilled perpendicular to face cleats (Kulander and Dean, 1993; Laubach and others, 1998) because they intersect more cumulative coal matrix, and more flow pathways (cleats) in the producing coal beds. Coal cleat orientations have been mapped in parts of Pennsylvania (McCulloch and others, 1974; and West Virginia (Kulander and others, 1980; Kulander and Dean, 1993). 8

19 Figure 3. Pennsylvanian coal beds, associated strata, and CBM producers in the main bituminous coal field of Pennsylvania and the northern coal field of West Virginia. The stratigraphic interval in which CBM has been produced is shown by the pink bar. Red bars are the major CBM beds. Asterisks indicate driller s terminology (after Markowski, 2001, Figure 7). 9

20 Historically, CBM has been produced at depths of 300 to more than 2,300 ft, but most completions are at depths of 1,000 ft or more (Milici, 2004). A cumulative coal thickness of more than 15 ft is generally considered favorable for CBM development with vertical wells (Milici, 2004). Bruner and others (1995) mapped areas in the Dunkard basin in which cumulative coal thickness in the Allegheny Formation (only) exceeded 15 ft. With the onset of horizontal drilling, cumulative coal thickness has become less important than lateral continuity of coal beds. Many horizontal wells are being drilled in the Pittsburgh coal in advance of underground mining in order to degas the coal and recover economic gas. CONSOL Energy, Inc. is currently degassing the Pittsburgh coal and testing the Upper Freeport coal for CO 2 storage with ECBM in the northern panhandle of West Virginia with horizontal wells. Although the study area is located in the MRCSP region, the CONSOL project is being conducted separately from our MRCSP project. The results of this research should be broadly applicable to the Dunkard basin region. Dunkard Basin CBM and CO 2 Sources CBM fields in the Dunkard basin are close to many of the large CO 2 sources in southwestern Pennsylvania and the greater Pittsburgh metropolitan area, which form a narrow belt from northern West Virginia into central Pennsylvania (Fig. 4). The main CBM trend is generally consistent with the trend of thick coals at depths of more than 500 ft mapped in Figure 1, and closely conforms to the regional structure. A significant number of large point sources are within a 50-mile radius of the main CBM-producing region. Many of the newer wells in West Virginia are in the panhandle, which is west of the area of review in Milici s (2004) report, and west of the line previously inferred for thermogenic gas (red line in Figure 1). Most of these wells are horizontal wells in the Pittsburgh coal. Although these wells are close to some of the large point sources along the Ohio River, they are less than 1,000 ft deep, which is shallower than the present guidelines for CO 2 injection for ECBM. Also, wells being drilled in advance of mining in the Pittsburgh coal could not be used for CO 2 storage 10

21 50 mi 50 km OH WV PA MD Bedrock Geology Permian and Pennsylvanian Pennsylvanian Faults CBM wells CONSOL CO 2 project CO 2 Sources More than 1 million tons Less than 1 million tons Figure 4. Point sources of CO 2 emissions relative to the CBM wells in the Dunkard basin. The pink dashed line outlines the minimum petroleum system area or CBM-producing area of Milici (2004) shown in Figure 2. with ECBM because the coal would be mined. Only unmineable coals should be considered for ECBM with CO 2. Barbour Co., W.V., is another area where CBM wells have been drilled outside of the area of review in Milici s (2004) assessment. These wells are southwest of the main CBM trend in northern West Virginia, and produce from the Kittanning and Freeport coal beds. Most of the wells have been drilled with CDX Gas multi-lateral pinnate horizontal drilling technology and are less than 1,000 ft deep. 11

22 Pocahontas Basin CBM The Pocahontas basin is part of the larger central Appalachian basin, and is defined as the region in southwestern Virginia and southern West Virginia in which the Lower Pennsylvanian Pocahontas Formation is preserved (Fig. 5). The Pocahontas Formation does not extend into southeastern Kentucky (Fig. 6). Milici (2004) included parts of southeastern Kentucky in the Pocahontas basin assessment unit in order to include Lower Pennsylvanian coalbed methane wells in southeastern Kentucky that produced from slightly younger strata (Fig. 6). Southeastern Kentucky is part of the central Appalachian basin but not the Pocahontas sub-basin. The southern West Virginia portion of the Pocahontas basin and adjacent parts of eastern Kentucky are in the MRCSP region. Southwestern Virginia, which covers the greatest area and has the most CBM production in the basin, is situated in the SECARB region. Figure 5. Central Appalachian basin major CBM fields in southwest Virginia and southern West Virginia (from Milici, 2004, Figure 14). AU=assessment unit. 12

23 The Pocahontas Formation is older than Dunkard basin strata in the northern Appalachian basin, and none of the major gas-producing coals continue northward into the Dunkard basin. Many of the target coal beds for CBM are in the Lower Pennsylvanian Pocahontas Formation (Fig. 6). The Pocahontas No. 3 and Pocahontas No. 4 coals are estimated to have 2.7 trillion cubic feet (Tcf) of gas in place, accounting for more than 50 percent of the in-place CBM in the central Appalachian basin (Reeves, 2003a). The Pocahontas No. 3 coal is a high rank, lowvolatile bituminous, low ash, low sulfur coal. In some areas it reaches semi-anthracite rank Figure 6. Pennsylvanian coal beds, associated strata, and CBM producers in the central Appalachian basin of southwestern Virginia, southern West Virginia, and southeastern Kentucky. The stratigraphic interval in which CBM has been produced is shown by the pink bar. Red bars are the major CBM beds. Asterisk indicates uncertain correlation. 13

24 (Milici and others, 2000). Many of the wells in Wyoming and McDowell counties, W.V., are in the Pocahontas No. 3 coal. Multi-lateral horizontal wells are drilled to degas the coal in advance of mining (Avary, 2004). Coal beds in the overlying Lee, Norton, and Wise formations (Fig. 6) have also been productive and are often treated with deeper coals to achieve greater cumulative coal thickness. Nolde and Spears (1998) estimated 4.49 Tcf of potential gas reserves in seven Norton Formation coal beds in Virginia. As in the northern Appalachian basin, cumulative coal thicknesses of more than 15 ft are generally needed for economic CBM development using vertical wells, and generally require the treatment of multiple coals (each less than 6 ft thick, and typically 2 3 ft thick) across some openhole interval (Milici, 2004). Increasingly, newer wells are using multilateral horizontal drilling. Horizontal wells generally target one or perhaps two thin seams, typically only a few feet thick. Cumulative CBM production in the southern West Virginia portion of the Pocahontas basin is 110 Bcf from Producing coals are low- to medium-volatile bituminous and increase in rank southeastward toward the Allegheny Front most of the CBM production is along that margin (Fig. 4). Recorded completion depths vary from 325 ft to more than 2,600 ft; most production occurs at depths of more than 1,000 ft (Lyons, 1996; Nolde and Spears, 1998; Milici, 2004). In general, central Appalachian basin coals have higher gas contents than northern Appalachian basin coals, and higher average daily rates of production (Lyons, 1996). SECARB has tested CO 2 -sequestration opportunities using ECBM in southwestern Virginia as part of their Phase II research (see field test section), which should be broadly applicable to the coals in southern West Virginia. The West Virginia part of the Pocahontas basin is included in SECARB s Phase II evaluation of CO 2 for ECBM in the central Appalachians (Ripepi et al., 2008; Ripepi and Shea, 2009). Pocahontas Basin CBM and CO 2 Sources Most of the CBM fields in the West Virginia portion of the Pocahontas basin are south of the major CO 2 -point sources in the region (Fig. 7). The closest sources are more than 20 miles 14

25 away from current production. Four large sources are within 50 miles of producing fields. Hence, significant transport will be needed to move captured CO 2 to the CBM fields for ECBM. Also, wells drilled in Wyoming and McDowell counties for degassing the Pocahontas No. 3 coal in advance of mining, would not be available for CO 2 injection, because the coal will be mined. Bedrock Geology Permian and Pennsylvanian Pennsylvanian Faults CBM wells SECARB CO 2 project CO 2 Sources More than 1 million tons Less than 1 million tons KY VA WV 50 mi 50 km Figure 7. Point sources of CO 2 emissions relative to the CBM wells in the MRCSP parts of the Pocahontas basin. The pink dashed line outlines the minimum petroleum system area or CBM-producing area of Milici (2004) shown in Figure 5. The majority of CBM production is in southwest Virginia, which is in the SECARB partnership (highlighted with different shading). ENHANCED COALBED METHANE RECOVERY One of the reasons coal beds are being investigated for CO 2 storage is the potential for ECBM recovery from coals, which would provide a value-added economic incentive for storing CO 2 (Stevens and Spector, 1998; Byrer and Guthrie, 1999; DOE, 2002, 2004). Using CO 2 for 15

26 ECBM has been shown to improve methane recovery (Reznik and others, 1984; Reeves, 2003a, 2003b; White and others, 2005). It is important, however, to make the distinction between using CO 2 for ECBM recovery and coal beds as large-scale sequestration reservoirs. Large-scale sequestration (1 million short tons/year of CO 2 ) would likely be difficult in most Appalachian coal beds or series of coal beds. Most Appalachian coal beds have low permeability and are relatively thin (less than 6 ft thick), which would mean relatively low injection rates, possibly the need for many injection wells, and potentially large plume areas for large-scale storage alone. Use of CO 2 for ECBM, however, is tenable. Results from current DOE-sponsored field tests in coals will help to determine possible injection rates in Appalachian basin coals and the actual potential for carbon storage in coals with or without ECBM. A variety of issues have been researched since the completion of the MRCSP Phase I report relative to using coal beds for carbon storage and ECBM. Some areas of critical research to using this technology include the development of screening criteria, the detrimental impacts of coal swelling and physical changes to coal structure, and varying sorption rates related to various physical and chemical variations in coal. Optimal Characteristics for ECBM with CO 2 Several investigations have looked at the conditions needed for effective ECBM with CO 2 (Gale and Freund, 2001; Pashin and others, 2003). The best coal beds for ECBM should be: (1) thick, (2) deep economically unmineable in the foreseeable future and beneath the level of current mining, but not so deep that porosity and permeability are decreased by increased pressure, (3) contain significant CH 4, (4) have minimal folding, faulting, or other compartmentalization although structure is important in CBM production in the basin, (5) laterally continuous, (6) vertically isolated in order to prevent leakage, (7) have adequate permeability for injection, (8) vertically concentrated few, thick coal beds across some thickness, rather than many thin coal beds across a greater distance, unless horizontal wells are being used in a single thick seam, and (8) contain brines with more than 3,000 mg/l total dissolved solids to meet U.S. Environmental Protection Agency Class II Underground Injection Control guidelines. 16

27 These criteria vary in the MRCSP Phase II study area. Coal thickness is extremely variable both within and between coals and this may be a detriment in some areas. In general, Upper Pennsylvanian coal beds producing CBM in the northern Appalachian basin are thicker and more uniform in thickness, dip, and composition than Middle and Lower Pennsylvanian coals in the central Appalachian basin (for example see Greb and others, 2008). Coal beds in the Kittanning and Freeport intervals, plus the Pittsburgh coal, account for more than 75 percent of the in-place gas reserves in the northern Appalachian basin (Reeves, 2003a). Moreover, these coal beds are mostly laterally continuous, relatively thick, compositionally uniform coal beds (Markowski, 2001; Appalachian Basin Resource Assessment Team, 2002). The principle gascontaining coals of the central Appalachian basin (i.e., Pocahontas No.3, Pocahontas No. 4, and Beckley-War Creek coals), in comparison, are thinner and more irregular in distribution and composition (Nolde, 1994; Miller, 1974; Greb and others, 2008). If CO 2 were to be used for ECBM, then presumably the coals, which have already produced methane, would have adequate space and permeability for CO 2 injection. Likewise, coals that have already produced methane are likely to have some lateral continuity and be vertically isolated, since they held methane prior to production. Most Pennsylvanian coals are overlain by low-permeability shales across at least part of their extent, and are underlain by lowpermeability paleosols, called underclays, which should aid in containment (in addition to adsorption mechanisms within the coal). Unfortunately, lateral changes in overlying rock facies are common in most portions of the coal-bearing interval. Lateral heterogeneity in intervening rock strata is more common in the Lower and Middle Pennsylvanian coal-bearing interval of the central Appalachian basin, than in the Upper Pennsylvanian coal-bearing interval of the northern Appalachian basin. Porous, saltwater-bearing sandstones overly some Lower Pennsylvanian coals in the central Appalachian basin, which would have to be considered in any injection project in which they were in contact with the coal reservoir or in communication with the coal through fractures (natural or well treatment). There are, however, discrete coal beds and coal zones that are known to be overlain by thick shales across large areas, or have overlying paleosols and coals that would act as redundant confining intervals, which could be preferentially chosen for CO 2 injection to help ensure confinement of injected CO 2. 17

28 Coal Swelling Injection of CO 2 into coal beds results in swelling of the coal matrix. Swelling decreases the width of cleats and reduces matrix permeability, especially near the well bore. Swelling may be the primary limiting factor for the future deployment of coal sequestration with ECBM (Pekot and Reeves, 2002; Reeves, 2003a, 2003b; Larsen, 2004; Pan and Connell, 2007; Day and others, 2008; Mazumder and Wolf, 2008), and research is ongoing to better understand its occurrence and to determine if there are ways to limit its deleterious effects relative to CO 2 storage with ECBM. Swelling in coals has been demonstrated to be heterogeneous in laboratory research. Swelling (1) is greater in the plane perpendicular to bedding than parallel to bedding (Ceglarska- Stefanska and Czaplinski, 1993; Larsen and others, 1997; Day and others, 2008), (2) varies with rank and lithotype (Karacan, 2003, 2007), (3) increases with decreasing carbon content (Reucroft and Patel, 1986; Karacan, 2003), and (4) tends to increase with rank and pressure (Walker and others, 1988; Karacan, 2003). There have been few field tests to document swelling caused by CO 2 injection, but several field demonstrations have experienced swelling. Loss of injectivity with swelling was encountered in the Fenn-Big Valley test in Alberta, Canada (Mavor and others, 2004), the Yuabri test in Hokaido, Japan (Shi and others, 2008), and the Allison unit test, San Juan basin, New Mexico (Reeves, 2003a, 2003b). The Allison unit injection project is the first field demonstration of CO 2 for ECBM in the United States. Carbon dioxide was injected into three coal beds with thicknesses of 22 ft, 10 ft, and 11 ft in the Fruitland Formation at depths of ,200 ft (Reeves, 2003b). Analyses of injection rates from four injection wells in the Allison unit found that swelling significantly reduced injectivity initially in the project, but that later injectivity slowly began to improve. Pressure transient data indicate permeability reductions of 99 percent near the well bore from coal swelling (Reeves, 2002) and a 60 percent loss in injectivity (Pekot and Reeves, 2002; Reeves, 2003b). This type of swelling would have significant consequences to a commercial injection project. In laboratory research, Pan and Connell (2007) suggested that the rate of coal swelling from CO 2 injection might decrease after reaching a maximum based on experimental data, which 18

29 might be what was observed with the long period of slow recovery in the Allison unit. Similarly, Karacan (2003) inferred that slight permeability improvement following initial decreases in permeability, should be expected at each increase in pressure within a seam. Although the Fruitland coals have lower rank, greater thicknesses, and greater depth than coal beds that would be targeted for ECBM in the Appalachian basin; the potential for significant coal swelling during CO 2 injection in Appalachian coal beds must also be considered. Although a major concern, coal swelling does not necessarily negate the possibilities of CO 2 for ECBM in the Appalachian basin. Coal swelling means that volumes or rates of daily CO 2 injection would decrease (on a per well basis), but injection might still be possible depending on reservoir pressures and the economics of CO 2 storage. For example, even with coal swelling in the Allison unit, more than 2 Bcf of CO 2 was injected (Gale and Freund, 2001), and natural gas production was increased to provide additional revenue (Reeves, 2002; Reeves, 2003a, Reeves and others, 2003). Also, enhanced methane recovery led to further depletion of the reservoir, declining reservoir pressure, and gradual improvement in injectivity (Reeves, 2002). It is also uncertain if all coals will swell in the same manner. As coal porosity and composition are heterogeneous, so too is coal swelling. In the northern Appalachian basin, the CONSOL injection project is using horizontal drilling, which may be a means to limit the impact of coal swelling. Another method for decreasing swelling may be injection of mixed gases. Injection of nitrogen (N 2 ) and flue gases in the Alberta field test resulted in increases in permeability (Mavor and others, 2004). In the Japanese test, injection of N 2 following decreased permeability with CO 2 injection, led to increased permeability and subsequent increases in CO 2 injectivity (Shi and others, 2008). Recent laboratory research on some western Canadian coal beds shows that injection of mixed N 2 and CO 2 (as occurs in flue gases) could improve CO 2 injection efficiency with only minor reduction in CO 2 sequestration capacity (Bustin and others, 2008). Research on mixing injected gases and other techniques need to continue to find methods to limit the impact of coal swelling. 19

30 Other CO 2 -Induced Physical Changes to Coal Carbon dioxide not only is adsorbed onto coal surfaces, it also is dissolved into the coal matrix (Karacan, 2003, 2007; Larsen, 2004). Dissolution into the coal matrix may rearrange the physical structure of the matrix, even plasticizing the coal or parts of the coal (Karacan, 2007). Laboratory studies of CO 2 sorption on the Pittsburgh (No. 8) coal from the Dunkard basin indicated that the coal matrix was plasticized following interaction with the injected CO 2. Changes in the physical structure of the coal matrix would change subsequent diffusion rates, adsorption, and solubility within the host coal (Goodman and others, 2005; Karacan, 2007). Alternatively, studies of CO 2 adsorption on Australian coals in laboratory experiments found no evidence of CO 2 plasticizing the coal matrix under pressure (Day and others, 2008). The differences suggest there may be different consequences for injection of CO 2 for different coals, which is not surprising since coal swelling and CO 2 sorption are also different for different coals, or even different parts of a coal bed (Karacan, 2003). Compositional Controls on CO 2 Sorption Research increasingly shows that coal type and rank influence sorption behavior in coals. Because coal bed compositions vary both between coal beds and within individual coal beds, sorption rates are likely to vary as well. High-vitrinite, low-ash coals appear to adsorb more CO 2 than low-vitrinite, high-ash coals at the same adsorption pressure because vitrinite-rich coals have more micropores than inertinite-rich coals (Clarkson and Bustin, 1996; Bustin and Clarkson, 1998). High-vitrinite coals may also have closer spacing of cleats (Laubach and others, 1998), which could provide more pathways for injection if coal swelling can be limited. Within the vitrinite maceral group, Mastalerz and others (2004) found a positive correlation between CO 2 sorption volume and telocollinite in bituminous coals of the Illinois basin, which are of similar age and composition to some of the gas-producing coals in the northern Appalachian basin. Fortunately, coals in the northern Appalachian basin tend to have high vitrinite contents. Clarkson and Bustin (2000) also found composition to be a significant influence on CO 2 adsorption, but indicated that moisture content and total gas pressure were more important. 20

31 Moisture content (in situ matrix water) may impede the exchange of CO 2 for CH 4 or block adsorption sites, which would mean adsorption might be greater in drier coals (Mazumder and Wolf, 2008). If CO 2 is used for ECBM, than most target coals will have been dewatered as part of primary methane production. Potential Environmental Issues CO 2 sequestration is a technology designed to decrease the environmental impact of carbon emissions. Care will be needed to ensure that carbon injection will not result in additional environmental impacts. Underground injection of carbon dioxide will be strictly regulated by EPA UIC regulations and appropriate state agencies. These regulations are designed to prevent contamination of potable groundwater, which is generally shallower than a few hundred feet beneath the surface. Coal beds used for ECBM with CO 2 will likely be at depths of more than 1,000 ft, and will have to be well below the level of potable water and adequately confined to prevent any disturbance to the water table. Similarly, the environmental concerns of CBM production are potential contamination of groundwater. During CBM recovery, saline formation waters are pumped from the coals to the surface where they are stored and treated. Water production and treatment are regulated by the government, whether for primary or enhanced CBM recovery, to ensure that the formation waters do not contaminate potable groundwater or surface waters. Another potential concern in ECBM projects might be the impacts of hydraulic fracturing on containment of injected CO 2 and migration of formation waters. In many CBM wells, water pressure is purposely increased near the well bore to fracture the coal and increase gas flow from the coal into the producing well. If fractures propagate outside of the coal there would be communication with overlying and underlying strata and the potential for leakage out of the coal zone. Relative to CO 2 injection, coal beds have an advantage over other types of reservoirs because injected CO 2 should adsorb and adhere to the coal matrix, which will help to keep the CO 2 contained. Still, care will be needed to ensure that injected CO 2 remains in the planned reservoir interval and does not flow into any fractures that would communicate outside of the interval. Injecting in deep coals with redundant overlying coal beds and secondary confining 21

32 intervals (well below the levels of mining and potable water) will help to minimize any risk of leakage to the water table or surface through existing fractures. Future ECBM projects would be designed so the injected CO 2 displaces or pushes CH 4 in the coal beds to several producing wells. In such cases, the producing wells also act as monitoring wells to see when and where injected CO 2 breaks through. Once CO 2 breaks through to producing wells, injection for ECBM would likely cease because the CO 2 would be diluting the produced gas. Careful monitoring of reservoir pressures and injection rates during CO 2 injection, and monitoring of surface gas composition in producing wells will aid in keeping track of the injected CO 2 underground. Continued laboratory research on target coal beds and field demonstrations in existing CBM fields will aid in determining if there are any other environmental issues specific to CO 2 injection. Protocols and guidelines will also need to be developed for injection and long-term monitoring/verification if large-scale deployment of this technology is realized. CO 2 FIELD TESTS IN THE REGION Northern Appalachian Basin Field Test CONSOL s Northern Appalachian basin field test involves two coal beds, the Pittsburgh and Upper Freeport coals in a 200-acre area of Marshall County, West Virginia (West Virginia s northern panhandle). At the test site, the Pittsburgh coal is 4 6 ft thick at a depth of approximately 700 ft and the Upper Freeport coal is ft thick at depths of 1,200 1,800 ft. The project began in 2003 and will be completed in This demonstration plans to test horizontal drilling for carbon storage with ECBM recovery. Horizontal drilling will maximize drainage of CBM and minimize the surface footprint of the injection operation. Horizontal drilling may also limit the negative impacts of coal swelling that might limit injectivity of a single, vertical well. The Pittsburgh coal is the upper of the two beds and is planned to be underground mined. Methane will be drained from the coal prior to mining in order to provide a safer working environment in the underground mine. Degasification in advance of mining has long been 22

33 practiced in deep mines of the Black Warrior basin in the southern Appalachians (see for example, Pashin and others, 2003). The Upper Freeport coal is the lower of the two seams and is too deep to mine. It will simply be degassed prior to injection of CO 2. Two wells were drilled with 3,000 ft of horizontal extension into the Pittsburgh coal in Thinning in the Upper Freeport coal resulted in only 2,200 ft of horizontal extension (Cairns, 2003; Plansynski and others, 2008). Although the project is ongoing, some initial results have been reported. Gas contents from core indicated the Pittsburgh coal had 136 standard cubic foot per short ton (scf/t), while the Upper Freeport coal had 182 scf/t. Initial results from two wells drilled into the Pittsburgh coal showed 10 thousand cubic feet per day (Mcf/d) for the north well in 2006, and Mcf/d for the south well from The Upper Freeport wells had less gas, recording 4, 10, and 41 Mcf/d from the three wells drilled into that coal in 2006 (Winschel and Douglas, 2005). On-line production data reported to the West Virginia Department of Environmental Protection (DEP) Office of Oil and Gas indicates 1,764 and 3,187 Mcf per day produced from for each of the two wells in the Pittsburgh coal. The two Upper Freeport wells had reported production of 12,971 and 434,146 Mcf from Water and gas from wells in both coal beds have been draining since In 2009, the center wells in the Upper Freeport Coal were converted to CO 2 injection wells, and a Class II underground injection control permit was obtained from the West Virginia DEP, Office of Oil and Gas (DOE, 2009). Injection of CO 2 into the Upper Freeport coal began in Injection rates of 27 short tons/day are planned for two years. As much as 20,000 short tons will be injected over the twoyear period, or until CO 2 breaks through to the producing well. Careful monitoring of injection rates and pressure will be critical to ameliorating any effects of swelling in the coal and for projecting the future potential of injection with horizontal drilling. Monitoring wells will examine horizontal migration of CO 2 in the coal and watch for any vertical leakage (Cairns, 2003; Plansynski and others, 2008; DOE, 2009). 23