Doe/netl-2012/1540 Mobility And Conformance Control For Carbon Dioxide Enhanced Oil Recovery (Co2-Eor) Via Thickeners, Foams, And Gels - U.s. Department Of Energy Page 207

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Turkish Petroleum’s Bat Raman field; Turkey; 2002; In situ Crosslinking of a Polymer
Solution; Conformance Control [Topguder, 1999; Sahin et al., 2007; Topguder, 2010;
Karaoguz et al., 2007; Karaoguz et al., 2004].
The Bat Raman field is located in southeast Turkey. It produces from the 4,300 ft. deep, 210 ft.
(gross) thick, heterogeneous, fractured Garzan Limestone formation of the Cretaceous age. The
o
crude is a heavy (10–15
API), viscous (450–1,000 cP) oil that contains little solution gas. As a
result, oil production from primary recovery between 1961 and 1986 was quite low, only 2%
OOIP. The formation pressure declined during this period from 1,800 psia to values as low as
400 psia.
A cyclic CO
injection scheme was piloted in 1986 in a 1,200 acre portion of the formation.
2
CO
huff-n-puff was then investigated. In 1988 the CO
injection was converted to a CO
flood
2
2
2
and soon thereafter the entire field was CO
flooded. Although the matrix permeability was 10–
2
100 mD, effective permeability values obtained from well tests were in the 200–500 mD range,
which is indicative of the existence of fractures, vugs, and connecting cracks. The presence of
this secondary permeability, combined with fingering due to the very unfavorable mobility ratio
and gravity segregation caused by the density difference between CO
and the oil, led to early
2
gas breakthrough and poor sweep efficiency.
+3
Laboratory tests indicated that polyacrylamide-based gels that would crosslink in situ via Cr
acetate could provide effective conformance control. For near wellbore treatments, a solution of
+3
3wt% Allied Chemical relatively low molecular weight Alcoflood 254S and 1.46% Cr
acetate
was tested, while large volume, deep penetration formulations were based on 1wt% of a
+3
moderately high molecular weight Alcoflood 935 and 0.1wt% Cr
acetate [Topguder, 1997].
Given the extensive vuggy and fractured zones, a decision was then made to use the latter
formulation.
About 10,000 bbl. of treatments were injected into a typical well over a two-day period.
Preparation of the polymer solution required low shear mixing and fresh water hydration of the
polyacrylamide, precise addition of the crosslinker at the wellhead, sampling during the
operation, and monitoring of the injection pressure, injection flow rate, and cumulative injected
volume of the solution. Three wells—BR-109, 116, and 124—were treated in July 2002, with
four more planned for 2004.
In general, there was little initial change in injection pressure as the solution apparently filled the
highest permeability vugs, but then the injection pressure increased during the remainder of
treatment. Therefore, the injection flow rate was gradually decreased to prevent formation
fracturing. After the treatment was injected, the well was shut in for a week, and then the CO
2
injection was incrementally ramped up to 1,200 psia over a month to prevent gel damage due to
the sudden application of high-pressure (1,200 psia) CO
. In one of the treatments, an offset
2
producer exhibited changes in fluid level indicative of communication with the injector, but after
gelation the communication was lost. This provided direct evidence of the gel’s ability to plug a
high permeability fracture path between these two wells. A year after the gel treatments, oil
production from the 19 offset producers was 720 BOPD, a 12% increase over the pre-gel value
176

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