MRCSP Phase I Geologic Characterization Report - Midwest ...

APPENDIX A: DEVONIAN ORGANIC-RICH SHALES
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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.