MRCSP Phase I Geologic Characterization Report - Midwest ...

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120 CHARACTERIZATION OF GEOLOGIC SEQUESTRATION OPPORTUNITIES IN THE MRCSP REGION Table A14-1.—Nomenclature of primary shale units Unit Reference Antrim Shale A.C. Lane, 1901, Michigan Mineralogy, vol 3., no. 1, p. 9. Named for exposures in Antrim County, northwestern Lower Peninsula, Michigan. Chagrin Shale C.S. Prosser, 1903, Journal of Geology, vol. 11, p. 521 (replaced the Erie Shale, underlying the Cleveland Shale and overlying the Huron Shale. Named for the Chagrin River, Cuyahoga County, Ohio. Chattanooga Shale C.S. Hayes, 1891, Geological Society of America Bulletin, vol. 2, p. 143. Named for Chattanooga, Tennessee. Cleveland Shale Member of the Ohio Shale J.S. Newberry, 1870, Ohio Geological Survey Report of Progress, 1869, p. 19,21. Named for exposures near Cleveland, Ohio. Huron Shale Member of the Ohio Shale J.S. Newberry, 1870, Ohio Geological Survey Report of Progress, 1869, p. 18. Named for exposures on the Huron River, Huron and Erie Counties, northern Ohio. Ohio Shale E.B. Andrews, 1870, Ohio Geological Survey Report of Progress 1869, p. 62. Named for the Ohio River hills in north-central Kentucky and Ohio. Dunkirk Shale Member of the Ohio Shale J.M. Clarke, 1903, New York State Museum Handbook 19, p. 24. Named for exposures on Lake Erie at Dunkirk, Chautauqua County, New York. Rhinestreet Shale Member of the West Falls Formation J.M. Clarke, 1903, New York State Museum Handbook 19, p. 23. Named for exposures along Rhinestreet, north from Naples, Ontario County, New York. Middlesex Shale Member of the Sonyea Formation J.M. Clarke, 1903, New York State Museum Handbook 19, p. 23. Named for abundant exposures in the town of Middlesex, Yates County, New York. Geneseo Shale Member of the Genesee Formation G. H. Chadwick, 1920, Geological Society of America Bulletin, v. 31, p. 118. Named for exposures in Geneseo, Livingston County, New York. Burket Shale Member of the Harrell Shale C. Butts, 1918, American Journal of Science, 4 th ser., v. 46, p. 523, 526. Named for black fi ssile shale exposed at Burket, Blair County, Pennsylvania. Marcellus Formation J. Hall, 1839, New York Geological Survey, 3 rd Report, p. 295-296. Named for exposures at Marcellus, Onondaga County, New York. The lower contact is typically sharp above carbonates to gradational above shales, and straightforward on geophysical logs. Minor to moderate topographic relief was developed on this surface in the western part of the basin prior to deposition of the shales. The uppermost Devonian Berea Sandstone and equivalent Bedford Shale generally conformably overlie the Upper Devonian shales in the western part of the Appalachian basin. In the eastern portion of the basin, the shales are overlain by thick sequences of Upper Devonian sandstones and interbedded shale (Figure 5). In the Michigan basin, the Antrim Shale gradationally overlies carbonates of the Middle Devonian-age Traverse Group and is overlain by the Upper Devonian-age Bedford Shale, Berea Sandstone or the Ellsworth Shale. The upper contact is highly variable across the region and typically indistinguishable and arbitrary in the absence of well-developed black shale. A lateral facies relationship exists between the upper unnamed member of the Antrim and the Ellsworth Shale on the western margin of the Michigan basin. LITHOLOGY Many of the Devonian shales, such as the Ohio and Antrim, are black to gray, thinly laminated, fissile, shales and siltstones. The western and northwestern areas are dominantly black shale, which grade eastward into gray shale and siltstone, and coarse-grained clastics of the Catskill delta complex farther east. Hosterman and Whitlow (1983) report that the shales consist of clay (30 to 75 percent) and quartz (20 to 50 percent) with varying amounts of pyrite and calcite being the primary accessory minerals. Clay minerals are primarily mixed layer clays (illite-smectite and illite-chlorite), chlorite, and kaolinite. The shale color (and density) varies based on the organic matter content (bitumen), which ranges from less than one percent to 27 percent (Zielinski and McIver, 1982). Pyrite occurs throughout the unit, but tends to be better preserved in the more organic-rich intervals. Total organic carbon analyses from nine Ohio Shale cores range from less than one percent to greater than 15 percent for the Appalachian basin in Ohio (Knapp and Stith, 1982). The lower portion of the Ohio is well known for largediameter, iron-rich concretions and for fossilized wood fragments along the outcrop in Ohio. Calcite often occurs as cementation at or near boundaries between the more and less organic units. Large carbonate concretions are also common in the Antrim throughout the Michigan basin. Matrix porosity estimated from geophysical logs ranges from 1.5 percent to 11 percent with an average of 4.3 percent, which is typical for Appalachian basin wells (Boswell, 1996). Recently acquired sidewall cores from an Ohio Shale well in eastern Kentucky were analyzed using mercury injection and indicate an average matrix porosity of 0.9 percent. The highest porosity, 2.4 percent, occurred in the Lower Huron Member. Permeability from the sidewall cores averaged 0.5 microdarcys (µd). Total porosity (matrix and fracture) for the Antrim in Michigan has been reported as nine percent (Hill and Nelson, 2000).
APPENDIX A: DEVONIAN ORGANIC-RICH SHALES 121 DISCUSSION OF DEPTH AND THICKNESS RANGES The maximum drilling depths for Devonian shales in the Appalachian basin occur in West Virginia, Maryland, and Pennsylvania close to the Allegheny Front. In south-central Pennsylvania, western Maryland, and northeastern West Virginia, the base of the shale sequence often exceeds 8,000 or 9,000 feet (Matthews, 1983). However, in eastern Kentucky, southern and southwestern Ohio, and western West Virginia where most Devonian shale drilling and production has taken place, depths are in the 2,000 to 3,000 feet range (Figure A14-2). In general, the Devonian shales increase in thickness eastward from the outcrop in Kentucky and Ohio and southeastward from Lake Erie to the Allegheny Front. Thicknesses range from zero feet in some areas of central Kentucky (southwestern-most extent of the MRCSP study area) to more than 8,000 feet in south-central Pennsylvania (Matthews, 1983) (Figure A14-3). In the Ohio and northern Kentucky region, the unit maintains a relative consistent eastward increase in thickness from about 200 feet at the outcrop to more than 3,000 feet. In the Michigan basin, the Antrim crops out around the margin of the basin, but is often concealed by overlying glacial deposits. Drilling depths exceed 3,000 feet in Osceola County, central Michigan. The Antrim thickness exceeds 650 feet in central and northwestern lower Michigan (Matthews, 1993). DEPOSITIONAL ENVIRONMENTS/ PALEOGEOGRAPHY/TECTONISM The depositional environments of the Devonian shales in the Appalachian and Michigan basins are considered transgressive basinfill sequences related to active subsidence and tectonism. The Ohio Shale depositional sequence was summarized by Potter and others (1981), Hamilton-Smith (1993), and Boswell (1996), . The shales were deposited in a shallow to deep foreland basin setting west of the active Acadian orogenic belt. Rapid transgression following the Middle Devonian unconformity resulted in sediment covering the Cincinnati and Findlay arches. The Bellefontaine outlier in western Ohio is the only remaining evidence for deposition on these structural highs (Swinford and Slucher, 1995). Controls on the preservation and distribution of organic matter continue to be debated, but the organics most likely accumulated under dysoxic to anoxic marine conditions. During initial basin subsidence, black shales accumulated under low energy conditions in a euxinic basin across the region, far from the Acadian orogeny and associated Catskill delta deposits. As active tectonism diminished, the black shales were replaced with prograding, gray clastic-rich sediments of the Chagrin/ Brallier facies, distal deposits associated with the Catskill deltaic sequence. Gray shales and siltstones of the Chagrin and Brallier thin westward and southwestward, and were deposited by far reaching turbidity currents from the Catskill delta. Sediment supply from the Chagrin and Brallier exceeded subsidence of the Appalachian basin, thus effectively eliminating the anoxic environments required for black shale deposition. The Michigan basin formed in multiple stages throughout the Paleozoic Era, but originated in an extensional regime during Late Precambrian rifting. Faulting, fracture development, growth of anticlinal structures, and regional basin subsidence occurred periodically throughout the Paleozoic, especially during major orogenic events on the eastern margin of the continent (Howell and van der Pluijm, 1999). In late Devonian through early Mississippian time, the fault-bounded Precambrian rift basin was reactivated during the Alleghanian orogeny causing a period of thermal subsidence yielding a classic sag basin (Catacosinos and others, 1990). Gamma-ray log response is key to stratigraphic analysis of the Devonian shales. Figure A14-4 illustrates the variation of gammaray tool response within the Devonian shale of the Big Sandy gas field, eastern Kentucky. Gray shales exhibit a gamma-ray response of 200 or more API units. In the more organic-rich black shales, the gamma-ray response exceeds 280 API units and may exceed 600 API units. Organic carbon content of the shale has been correlated to the uranium content (Potter and others, 1981). Schmoker (1993) demonstrated the relationship between log response and organic content. SUITABILITY AS A CO 2 INJECTION TARGET OR SEAL UNIT The suitability of the Devonian shales for CO 2 injection and sequestration has not been demonstrated, but should be considered in areas where the geologic controls are well known and predictable. The following examples support this hypothesis. It is most commonly assumed that the very low permeability (in the microdarcy range) makes shales more generally appropriate as a sealing unit. However, in the San Juan basin, CO 2 injection has been successfully demonstrated in coals, another organic-rich, low permeability, continuous, fractured reservoir. The similar behavior of gas production from the Devonian shales as compared to CBM indicates they may also serve as sequestration targets. Natural fracturing plays an important role in development of the shales as both a gas producing reservoir and a possible sequestration target. Methane adsorbed on organic matter and clay mineral surfaces (Hamilton-Smith, 1993) desorbs as reservoir pressure declines, thus theoretically creating potential new adsorption sites. Matrix porosity and organic matter content ultimately control the total volume of gas trapped in the shale. Permeability controls the diffusion rate of desorbed methane through that matrix. It is in the fracture system that flow measured in darcies dominates, facilitating the production of natural gas. In general, production in more highly fractured areas exhibits a relatively rapid decline as free gas in the fracture system is depleted, followed by an often decadeslong period of steady production controlled by the rate of methane desorption and diffusion through the fracture system. In areas with a less extensive fracture network, production often increases to reach a plateau of steady production analogous to CBM production history. Current research by Nuttall and others (2005) demonstrates a CO 2 adsorption capacity averaging 42.9 standard cubic feet per ton (scf/t) of shale (at expected reservoir pressures of 400 psi). Results from experiments to test the diffusion rate of CO 2 through the shale and any associated displacement of methane are currently being interpreted. Research to model shale gas production histories and investigate CO 2 injection is also needed. Available reservoir pressure and temperature data indicates that CO 2 can be injected as a gas in these organic-rich reservoirs. It is expected that the fractured black shale intervals will trap CO 2 adsorbed onto the surfaces of organic matter and clay minerals. The gray shale intervals, relatively lacking in organic matter and less fractured, are more likely to serve as permeability barriers or reservoir seals. To evaluate the opportunity for an effective reservoir seal, those areas where the shale is either very thick or at drilling depths of at least 1,000 feet need to be assessed. In those areas, where the shale is often gas productive, overlying Mississippian and Pennsylvanian shales and other impermeable units are anticipated to provide secondary sealing capacity. The Devonian shales are expected to be most suitable as a sequestration target where they are sufficiently deep, thick, organicrich, and fractured; that is, in the best shale gas producing areas.
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Characterization of Geologic Seques
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ABOUT THE MRCSP The Midwest Regiona
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CONTENTS About the MRCSP ..........
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CONTENTS Figure A14-2.—Structure
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1 CHARACTERIZATION OF GEOLOGIC SEQU
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BACKGROUND INFORMATION 3 (a minimum
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INTRODUCTION TO THE MRCSP REGION’
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GEOLOGIC MAPPING PROCEDURES, DATA S
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OIL, GAS, AND GAS STORAGE FIELDS 27
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CO 2-SEQUESTRATION STORAGE CAPACITY
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CONCLUSIONS AND REGIONAL ASSESSMENT
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REFERENCES CITED 47 National Confer
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49 APPENDIX A Geologic Summaries of
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APPENDIX A: PRECAMBRIAN UNCONFORMIT
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APPENDIX A: CAMBRIAN BASAL SANDSTON
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APPENDIX A: BASAL SANDSTONES TO TOP
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APPENDIX A: UPPER CAMBRIAN ROSE RUN
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APPENDIX A: UPPER CAMBRIAN ROSE RUN
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Page 127: APPENDIX A: DEVONIAN ORGANIC-RICH S
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Page 135 and 136: ( ( ( ( APPENDIX A: PENNSYLVANIAN C
Page 137 and 138: APPENDIX A: PENNSYLVANIAN COAL BEDS
Page 143 and 144: APPENDIX A: LOWER CRETACEOUS WASTE
Page 151 and 152: APPENDIX A: REFERENCES CITED 143 Sa
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