MRCSP Phase I Geologic Characterization Report - Midwest ...

OIL, GAS, AND GAS STORAGE FIELDS
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Table 4.—Summary of oil and gas production, by state, within the MRCSP region
State
Year First
Commercial
Production
Total Number Total Number Total Oil Yearly (2004)
of Wells Productive Production Oil Production
Total Gas
Production
(mcf)
Yearly (2004)
Gas
Production
(mcf)
Indiana (northern)* 1886 15,000 400 107,000,000 3,000 * 750,000
Kentucky 1860 250,000 63,190 772,532,160 2,548,105 5,388,675,103 94,258,790
Maryland 1951 220 7 0 0 48,752,678 36,276
Michigan 1925 53284 28720 1,243,000,000 6,393,353 6,643,000,000 193,141,644
Ohio 1860 258,897 216,640 ~1,105,000,000 5,785,338 >8,009,749,438 90,301,118
Pennsylvania 1859 ~350,000 Unknown >1,380,944,000 >1,708,435 >11,026,657,000 >171,042,843
West Virginia 1859 ~150,000 ~135,000 584,024,000 1,474,000 18,650,000,000 201,770,000
*Figures reported for northern Indiana only which is dominated by the historic Trenton oil and gas fi elds.
Because of the age of this drilling, these numbers are estimates and a total gas production fi gure is unknown.
(1995) concluded of this amount, only about 11.5 TCF is technically
recoverable. Recently, Milici (2004) estimated a limited portion of
northern West Virginia and southwestern Pennsylvania contained
reserves of almost 5 TCF of technically recoverable CBM; however,
his assessment did not provide an estimate for the entire northern
Appalachian coalfields. Regardless, based on these numbers, many
regions of the northern and central Appalachian basin contain significant
potential for CBM by enhanced gas recovery methods that use,
and more importantly would sequester, anthropogenic CO 2.
In a typical oil reservoir, primary production techniques (allowing
natural pressures to produce the oil or pumping the well) obtain
only about 10 percent of the total amount of oil trapped. Many
secondary-recovery technologies used to recover additional oil and
gas from reservoirs include waterflooding, reinjection of produced
natural gas, and steam and CO 2 flooding. Different formations respond
differently to various enhanced oil recovery (EOR) methods;
thus, the optimal EOR technology for each reservoir must be decided
after careful study of the reservoir rock and fluid properties.
A model is then developed and a pilot injection project is initiated
to test the model.
The reservoir of a successful EOR project can usually be expected
to produce at least another 10 percent of the original oil-in-place.
Therefore, by widely applying EOR practices in the region, it may
be possible to produce hundreds of millions of barrels of additional
oil that otherwise would stay in the ground unused. Such practices
could also add hundreds of jobs to the region.
Secondary recovery accounts for less than one-half of one percent
of the oil production in Ohio compared to as much as 25 to 50
percent in surrounding states in the Appalachian basin (Blomberg,
1994). Pennsylvania was an early pioneer in secondary recovery
techniques, especially waterfloods. Indeed, by the 1950s as much as
80 percent of the crude oil produced in Pennsylvania was from waterflood
operations (Harper and Laughrey, 1987). Currently, Ohio
has about 64,000-producing oil and gas wells; approximately half of
these are oil stripper wells (producing less than 10 barrels per day).
It has been estimated that 10,000 of these oil wells would benefit
from enhanced oil recovery techniques (Schrider, 1993). Premature
oil-well abandonment results in the loss recovery of many millions
of barrels of oil reserves as well as jobs, and a continued reliance on
foreign oil imports. While water flooding and other methods have
been applied in the region, many with great success, some reservoirs
have not responded favorably to these efforts. Carbon dioxide flooding
technology may work in some of these reservoirs to enhance
recovery, or at least be better than some of the earlier attempted
methods used in the infancy of enhanced recovery technology. Cooperative
efforts between governmental and industrial partnerships
to test and apply CO 2-enhanced recovery technology in the region
may help to impede the declining trend in domestic oil production
and enable the nation to become less dependent on foreign imports.
Carbon dioxide is one of the best mediums used for EOR because
of its unique properties—low temperature and pressure to stay in supercritical
phase, low viscosity, and it is soluble with oil and native
formation fluids. In a typical application, CO 2 is initially injected
into a geologic unit to form a bank that goes into solution with the
naturally occurring oil and brine. Water is then injected behind the
CO 2 bank to help increase formation pressure and push the CO 2/oil
bank away from the injection wells and towards the producing wells
(Figure 17). Alternating cycles of CO 2 and water are repeatedly injected
into the well throughout the life of the EOR project. The CO 2,
in solution with the oil, lessens the viscosity of the oil and aids its
movement through the reservoir porosity system.
Carbon dioxide produced from natural reservoirs has been used
for decades in the southwestern U.S. (Colorado, New Mexico, and
Texas) to enhance local oil field production. Hundreds of miles of
pipelines have been built to transport the CO 2 from these reservoirs
to the producing oil fields. Furthermore, since the early 1980s, over
400 million tons of CO 2 have been purchased from this network and
used to produce approximately 650 million barrels of incremental
oil (Martin, 2002). Yet, there has never been a large, economical
source of CO 2 available in the Appalachian and Michigan basins for
EOR use; thus, this method of enhanced recovery is atypical in the
MRCSP region. If large-scale capture of anthropogenic CO 2 comes
to fruition in the MRCSP region, it is anticipated a regional network
of pipelines will develop to distribute the CO 2 to candidate oil fields
as well as to appropriate saline storage reservoirs.
Figure 18 illustrates the 10 largest oil and gas fields greater than
2,500-feet deep within the MRCSP region. These fields would most
likely be among those first considered for enhanced production
assisted by CO 2 or use as CO 2-storage reservoirs. Table 5 lists the
storage properties and conservative estimates for the amount of CO 2
that may be sequestered within these fields. Although oil and gas
reservoirs in the MRCSP region contain less volume capacity compared
to the region’s saline formations, their trapping abilities and
value-added prospects should make them some of the first geologic
units to be utilized for CO 2 sequestration.
In Phase II, the MRCSP team plans to expand its study of oil and
gas systems in the region by defining those reservoirs best suited for
CO 2 EOR operations, and perhaps implementing at least one EOR