Page 126 - Fundamentals of Enhanced Oil and Gas Recovery

114 Pouria Behnoudfar et al.

is a very good miscible agent. When added to the primary and secondary recovery
(waterflood) of about 50%, the total recovery in this pilot is expected to be around
70% OOIP, which is well above the average for most fields.

4.3.4.2 Immiscible Weeks Island Gravity Stable CO 2 Flood
This sand, which is up against a salt dome, is highly dipping (30 degree dip) and is
very permeable both vertically and horizontally. The initial reservoir pressure for this

sand was 5100 psia at a reservoir temperature of 225 F, but at the time of the pilot,
the pressure was lower. The pilot lasted 6.7 years and consisted of one up-dip injector
and two producers about 260 ft down-dip. Following a waterflood, gas was injected
up-dip so that gravity would stabilize the front in a relatively horizontal interface. The
main idea of this gravity stable flood is that the gas oil contact (oil bank) will move
down vertically recovering oil and displacing it to the down-dip production wells.
This process can be highly efficient (good volumetric sweep) as long as there is good
vertical permeability, and the gas interface is stable and moves vertically downward.
The gas injected at Weeks Island was a mixture of CO 2 and about 5% plant gas.
The plant gas was used to lighten CO 2 so that the gas oil interface is more stable.
Injection of plant gas with CO 2 , however, was found unnecessary to ensure a gravity
stable flood at Weeks Island as CO 2 was effectively diluted by dissolved gas (methane)
from the reservoir oil [46].
At the reservoir temperature of 225 F and pressure at gas injection, the flood was

immiscible, not miscible. Nevertheless, a pressure core taken in zones where the gas tra-
versed was nearly “white” with average oil saturations in the CO 2 swept zone of
approximately 1.9%. This low oil saturation value is lower than miscible flood residuals,
S orm , that are typically observed due to oil-filled bypassed pores. The unexpectedly
good recovery demonstrates that even immiscible floods when properly designed can
achieve good extraction of oil components by gravity drainage. A subsequent commer-
cial test of the gravity stable process was not as successful largely because of significant
water influx down-dip of the production wells. Injection of CO 2 largely pressurized
the gas cap but did not cause the gas oil interface to move vertically downward. A
gravity stable process like this would be very effective as long as water influx is relatively
small. Perhaps, one solution could have been outrunning the aquifer with water pro-
duction wells or trying to plug off water influx. One difficult problem also encountered
was the production of the thin oil bank owing to both gas and water coning. The sec-
ond producer was not planned but was drilled to measure saturations in the oil bank
and to speed oil bank capture. Immiscible gas floods in general can achieve better dis-
placement efficiency as a secondary recovery method if gravity override is controlled,
than for waterfloods owing to decreased oil viscosity, oil swelling, IFT lowering, extrac-
tion of oil components, and the potential for gravity drainage as occurred at Weeks
Island. Immiscible gas floods could also be a good alternative for reservoirs with injec-
tivity issues when water is used. Two main disadvantages of immiscible gas flooding