Page 290 - Fundamentals of Enhanced Oil and Gas Recovery

278 Mohammad Ali Ahmadi

fracturing operation. The well layout created a toe-to-heel injection pattern. The dis-
tance from the injector to the nearest hydraulic fracture of each offset producer was
almost the same. When gas broke through at the toe end, the toe portions of the pro-
ducer were plugged to alleviate gas cycling. The injected gas continued moving to the
next port. This pattern enabled one injector to serve the gas requirement by nine pro-
ducers. For the producers with heels close to the injector, a straddle packer system
called “scab-liner” technique was applied at the immediate heel port [1].
The pilot test was started in December 2011; at the starting point of the project,
the injection rate was 300 MSCF/day at the injection pressure of 500 psi. When com-
pression was added in March 2012, the injection rate was increased to 1 MMSCF/day
at 1000 psi. Immediately, gas broke through two pattern wells. The oil production
rate decreased to 53 bbl/day by July 2012. After workovers, oil rates consistently
increased in all of nine producers and the total rate climbed to 295 bbl/day. The aver-
age decline rate of the pattern wells decreased from 20% before gas injection to 15%
after gas injection [1].
From this pilot test different valuable point could be learned. The first one is the
producer to injector ratio highly affects the performance of the project from an eco-
nomic viewpoint; this parameter is normally one to one in a case of conventional
water flooding. The second point is very low investment costs of carbon dioxide
injection compared to water injection scenario.
ACO 2 flooding pilot was performed in the Fuyang Layer in the Fang-48 fault
block, Song-Fang-Dun Field, Daqing, China, starting in March 2003. The ratio of
production well to injection well in this case is 5 to 1. At the end of two years from
injection started the total cumulative injected carbon dioxide was 0.33 reservoir pore
volume (PV). It should be noted that the injection well was not fractured in this pilot
test. Injectivity of carbon dioxide in this case is much higher than the water injectiv-
ity; it is almost 6.3 times higher. The performance of CO 2 injection in this pilot test
was promising.
One CO 2 huff-n-puff injection pilot was conducted in the Elm Coulee Field in
the Bakken Formation in the North Dakota area in 2008 [40]. There was no injectiv-
ity problem associated with injection of CO 2 at 1 MMSCF/day; the injection period
took 30 days. According to the production history before and after performing such
an EOR method, there was no significant improvement on oil recovery factor from
this test.
Another CO 2 huff-n-puff field test was performed in Richland County in the
Montana part of Bakken reservoir in 2009. Well configuration for this test was hori-
zontal well, which stimulated using hydraulic fracturing operation. The injection
period took 45 days, in this time the cumulative injected carbon dioxide was 45 mil-
lion cubic feet. After injection process, put the well in shut down model for 64 days;
this time was a soaking time. After soaking time, the well started to production and