MRCSP Phase I Geologic Characterization Report - Midwest ...

80 CHARACTERIZATION OF GEOLOGIC SEQUESTRATION OPPORTUNITIES IN THE MRCSP REGION
structures are absent or have had little or no effect on the interval.
The shales, particularly the very argillaceous and organic-rich
shales of the Maquoketa, Clays Ferry, Utica, and Point Pleasant
formations, should provide excellent sealing capability. Like the
Upper Devonian organic-rich shales, they probably have low matrix
porosities and permeabilities, even in fractured zones that would
provide effective seals for sequestration targets in lower strata. Although
the formation is characterized as fractured, joints within the
Maquoketa have collapsed due to the fissile nature of the shale, and
where present, the low hydraulic conductivity of the rock inhibits
fluid flow. In fact, it has been referred to as the Maquoketa Confining
Unit in regional aquifer studies (McGarry, 1996). It is highly
likely the same attributes will be found within the other Upper Ordovician
shales as well.
Lack of measured physical parameters for these strata in areas
not known to produce oil or gas will be a problem in evaluating the
rocks for sealing potential. A considerable amount of research will
be necessary to determine these parameters prior to initiating any
injection projects.
Potential Injection Targets
There are at least four targets for sequestration potential in the
Knox to Lower Silurian Unconformity Interval: 1) fractured or
coarse-grained bioclastic carbonates; 2) enhanced gas recovery in
thick organic-rich black shales of the Utica/Point Pleasant; 3) fractured
Bald Eagle and Oswego sandstones and conglomerates; and 4)
possible fractured or diagenetically altered Juniata sandstones.
Ordovician Carbonates—According to Sullivan (1983) and Nuttall
(1996), stratigraphic traps occur in the upper part of the Lexington
Limestone in Kentucky, sealed by fine-grained, impermeable
strata and tightly cemented grainstones. Net pay thickness averages
10 feet, and average matrix porosity is 11.8 percent with a maximum
porosity of 15 percent. Moldic, interparticular, intraparticular, and
intercrystalline porosity types dominate. Nuttall (1996) reported
that a core from Clinton County, Kentucky had an average reservoir
permeability of 57.1 millidarcies (md) and a maximum permeability
of 293 md. In this particular area of Kentucky, the Ordovician carbonates
are too shallow for effective sequestration (less than 2,500
feet), but similar reservoir zones in the Trenton Limestone in deeper
parts of the Michigan and Appalachian basins could ultimately be
useful for sequestration. This is especially true in areas where porosity
and permeability occur as a result of fracturing. Production
from fractured Black River/High Bridge and Trenton/Lexington
reservoirs in central Kentucky and West Virginia appears to be from
open, unmineralized fractures, probably related to reactivation of
deep-seated faults, although Hamilton-Smith and others (1990)
acknowledge that minor secondary mineralization might help keep
the fractures open. Dolomitized fracture zones and grainstone facies
account for much of the upper Black River/High Bridge and
Trenton/Lexington production in southeastern Michigan, Kentucky,
central Ohio, south-central Ontario, north-central Pennsylvania, and
south-central New York. In areas affected by large fault systems
with sizeable gouge zones, fluids interacted with the gouge to create
thick zones of mineralization and vugular porosity within the zones,
whereas smaller fault systems are more likely to have good intercrystalline
porosity development (Wickstrom, 1996).
Utica Shale and Point Pleasant Formation—Both the Utica and
Point Pleasant consist of dark gray to black, organic-rich shales,
with the Point Pleasant also containing interbedded Trenton-type
limestones. Many authors (for example, see Cole and others, 1987;
Wallace and Roen, 1989; Ryder and others, 1991; Wickstrom, 1996)
consider the Utica/Point Pleasant interval to be the source rocks for
the hydrocarbons found in the underlying Trenton and Black River
carbonates, as well as many of the overlying units (Bald Eagle, Medina,
Tuscarora, Lockport, etc.). The Utica /Point Pleasant interval
is more than 700 feet thick in parts of central Pennsylvania, but thins
to the northwest until it is only about 100 feet thick in northwestern
Ohio (Wickstrom, 1996). Because of their thickness and depth below
2,500 feet in much of the Michigan and Appalachian basins, the
Utica/Point Pleasant shales could have potential for sequestration
through enhanced shale gas recovery. Gas content probably varies
regionally with changes in thickness, pressure, organic carbon content,
and thermal maturity, as in the Upper Devonian black shales
of Appalachian and Michigan basins (Boswell, 1996). The interval
does not have a history of gas production (although strong shows
through the interval are regularly noted), so it would require substantial
research to determine how effective the shales would be to
both sequestration and gas production.
Bald Eagle and Oswego Formations—The Bald Eagle Formation,
where it produces natural gas in north-central Pennsylvania
at depths of 12,900 to 13,272 feet, is a naturally fractured reservoir
in which the fractures are vertical to subvertical and run parallel to
structural axes (Laughrey and Harper, 1996). There is no known
production from the Oswego Sandstone in the MRCSP study area,
but owing to lithologic similarities with the Bald Eagle, it probably
would also serve as a producing reservoir and potential sequestration
target in zones of intense fracturing. The sandstones from the
pay interval consist of moderately sorted to well sorted, fine- to
medium-grained, lithic arenites. Monocrystalline quartz and chert
dominate composition, but detrital and authigenic feldspars, some
altered to chlorites and mixed-layer illite-smectite, mica, low-grade
metamorphic rock fragments, and trace amounts of homblende and
pyrite also occur. Dolomite, with some minor calcite, comprise the
principal cement in the matrix, but they also contain minor authigenic
quartz cement (Laughrey and Harper, 1996). The sandstone
matrix has relatively low porosity and permeability, which contributes
to the seal. In addition, syntectonically precipitated minerals,
such as quartz, hematite, and calcite, often partially fill the fractures.
Upward-decreasing grain size, increasing clay content, and shale
beds in the overlying Juniata Formation might assist in sealing the
reservoir (Laughrey and Harper, 1996). Porosity and permeability
are extremely variable—fracture zones have porosities as high as
30 percent, whereas matrix porosities tend to be only two to eight
percent and matrix permeability was calculated at 0.07 md in the
reservoir, with all of the production coming from fracture permeability
(Laughrey and Harper, 1996)
Juniata Formation—Although Laughrey and Harper (1996)
consider the shales and fine-grained sandstones of the Juniata Formation
to contribute to the seal for Bald Eagle/Oswego reservoirs,
there is some potential for Juniata sandstones to act as sequestration
targets. This apparent discrepancy in interpretation is the result of
confusion of terminology. As Thompson (1970, 1999) has shown,
the Bald Eagle/Oswego and Juniata are artificial lithologic constructs
based on color differences—the Bald Eagle/Oswego is gray,
and the Juniata is red. Inasmuch as the color boundary between the
two formations varies by up to 656 feet within the Upper Ordovician
clastic lithofacies, Thompson (1970) recommended that the lithofacies
were far more consistent and meaningful than the formation
names. Thompson (1970, p. 1256, 1257) described lithofacies D
(Figure A5-3) as “unfossiliferous, cross-bedded medium- to coarsegrained
sandstone and conglomerate, with essentially no siltstone or