Page 160 - Enhanced Oil Recovery in Shale and Tight Reservoirs

144 Enhanced Oil Recovery in Shale and Tight Reservoirs

central well is used as a CO 2 injection well. The performance of huff and
puff is compared with that of CO 2 flooding. In gas flooding the central
well injects CO 2 from 450 to 1450 days. In the huff-n-puff, the central
well injects 60 days, soaks 10 days, then produces 120 days, and this process
is repeated for six cycles until 1450 days for the huff and puff mode. The
simulation results show that the incremental oil recovery over the primary
depletion for the flooding mode is higher than for the huff and puff
mode. The better flooding results are probably caused by her model in
which only the center well is changed from primary depletion to huff and
puff or continuous injection. For such model setup, the huff and puff benefit
cannot be realized in the two side wells. But the benefit of continuous in-
jection is well captured by the two side wells. Another reason may be the
partial loss of soaking benefit, as her model does not include molecular diffu-
sivity. The third reason may be that the injection volume by one well for
60 days is far not enough. Probably a more important reason is the small nat-
ural fracture spacing (2.27 ft) in her model. The matrix permeability is
around 300 nD, and the effective permeability in the SRV is 31 mD.
Such a high permeability model will make the gas flooding feasible.
Yu et al. (2014a) did a sensitivity study of CO 2 injection to enhance dry
gas recovery in Barnett reservoirs. They found that CO 2 flooding is a good
option to enhance gas recovery, but CO 2 huff and puff is not because most
of the injected CO 2 quickly flows back during the puff period. In their
simulation model, the wells were under primary production for 5 years,
injected for 5 years, soaked for 5 years, and produced for the test of 15 years.
Obviously, the soaking time and the subsequent puff time are too long. Such
huff-n-puff operation is far from the optimized. Therefore, the huff-n-puff
cannot be compared with the flooding mode for performance. Note this is a
case to produce dry gas (methane).
Schepers et al. (2009) simulated CO 2 sequestration and its enhanced gas
recovery in the Devonian gas shale of Eastern Kentucky, considering organic
matter in the shale has a greater sorption affinity for CO 2 than natural gas
(methane). They compared continuous CO 2 injection with huff-n-puff
CO 2 injection. The average formation permeability is 18 mD. The simulated
pattern is one injector and three producers in a 40-acre spacing. The gas
recovery of huff-n-puff CO 2 injection is 2.0% compared with 2.2% without
CO 2 injection. It is found that a significant amount of CO 2 is produced back
during the puff period. The huff-n-puff parameters are 5 days of injection,
1 month of soaking, and 3 months of production. 300 tons of CO 2 are
injected. However, the gas recovery factor for the continuous gas injection