MRCSP Phase I Geologic Characterization Report - Midwest ...

90 CHARACTERIZATION OF GEOLOGIC SEQUESTRATION OPPORTUNITIES IN THE MRCSP REGION
The Medina Group is comprised of interbedded sandstones,
mudrocks, and some carbonates that were deposited under variable
conditions (Laughrey, 1984; Laughrey and Harper, 1986; McCormac
and others, 1996). As a result, this reservoir is heterogeneous
because of variations in several rock characteristics, including grain
size, type and degree of cementation, clay content, and pore geometry
(McCormac and others, 1996). This is evidenced in the three
major facies of this sequence, the Grimsby Formation, Cabot Head
Shale, and Whirlpool Sandstone as described above. Due to these
lithologic variations within the Medina Group, detailed characterization
of this unit for injection potential needs to be performed at
each prospective site.
Figure A7-5 illustrates typical geophysical log curves for the
Medina Group in the northern Appalachian basin. The gamma-ray
signature demonstrates the relatively thick, sandy nature of the
Grimsby, the increasing-upward siltstone/sandstone laminations
within the Cabot Head Shale, and the abrupt, sandy signature of the
Whirlpool Sandstone as it overlies the Queenston Formation. This
gamma-ray response has been collectively referred to as a “broken
sandstone” signature by Laughrey (1984).
The porosity and permeability of the Medina Group varies due
to both depositional and diagenetic processes. The deposition of
mudrocks isolated sandy and silty layers of the Grimsby Sandstone
and the upper Cabot Head Shale, creating permeability barriers
between these reservoir rocks. Diagenesis has altered the relatively
tight, primary porosity in the northern portion of the basin, creating
two major types of secondary porosity, intergranular and moldic.
The secondary intergranular porosity is the result of dissolution of
primary calcite cement and grain edges, and moldic porosity is due
to the corrosion of silica cement and dissolution of feldspar minerals
(McCormac and others, 1996). However, diagenesis does not
always enhance porosity in this reservoir. Secondary cementation
by authigenic silica has been observed to reduce porosity, in some
cases surrounding entire grains to destroy the primary porosity
(Laughrey, 1984).
Work performed by Laughrey (1984) in the Athens Field of Crawford
County, Pennsylvania, identified several porosity types in the
Medina Group, from relict, primary porosity to microporosity, intraconstituent
porosity, and fracture porosity. The occurrence of fracture
porosity in the Medina and equivalent units has been documented
to a limited extent in other parts of the basin as well (McCormac
and others, 1996). In northwestern Pennsylvania, Laughrey (1984)
associated the highest porosity zones with those areas influenced by
both depositional environment and diagenetic phenomena.
Figure A7-5 illustrates typical porosity curves for the Medina
Group in the northern part of the basin. The crossover between
density porosity and neutron porosity curves is shown with light
gray shading and indicates a gas effect in the porous zones in the
Grimsby Sandstone, the transitional, silty sandstones of the Cabot
Head Shale, and the Whirlpool Sandstone. Medina Group porosities
range from 2 to 23 percent across the basin, and average 7.8 percent
(McCormac and others, 1996).
Medina Group permeabilities are widely variable, ranging from
less than 0.1 md to 40 md (McCormac and others, 1996). In northwestern
Pennsylvania, Medina permeabilities fall on the lower end
of this range (Laughrey, 1984). Even so, the Perrysville Consolidated
Field (Ashland County, Ohio) recorded average permeabilities of
over 100 md, and isolated permeabilities of individual layers in this
sequence can have permeabilities in excess of 200 md (McCormac
and others, 1996).
Brines in the Medina Group of Pennsylvania have salinity values
ranging from approximately 95,000 to 280,000 parts per million
(ppm). The primary components of these brines are calcium, sodium,
and chloride, with lesser amounts of magnesium, strontium, po-
Figure A7-5.—Gamma-ray and porosity geophysical log curves for the Madura #1 (API# 3708520801), a typical Medina gasproducing
well in Mercer County, Pennsylvania. The gamma-ray response has been described as a “broken sandstone” signature,
and the crossover of neutron porosity and density porosity curves illustrates a gas effect in the porous, gas-bearing zones of this
sequence.