Summary
Secondary- and tertiary-recovery processes based on gas injection can extend
the life of waterflooded reservoirs by maximizing the oil recovery. However,
the injection strategy needs to be studied carefully to optimize the overall
sweep efficiency. In particular, the impact of possible water blocking on the
recovery has to be addressed. For that purpose, a series of experiments was
performed under reservoir conditions on a carbonate rock type to compare the
displacement efficiencies of a secondary gas injection, a tertiary gas
injection, and a simultaneous water-alternating-gas (SWAG) injection.
The experiments were carried out on composite cores consisting of several
carefully selected reservoir core plugs of the chosen rock type. The operating
pressure was lower than the minimum miscible pressure (MMP) and reflected the
current reservoir pressure. Phase exchanges were monitored continually during
the hydrocarbon recovery, including the chromatographic analysis of the
produced gas.
The final oil recovery resulting from the three types of experiments was
very good [approximately 90% original oil in place (OOIP) at surface conditions
after 6 pore-volume (PV) injection] and quite similar within the expected
experimental error, regardless of the sequence of gas injection. The low
remaining oil saturation (ROS) values observed were consistent with competing
processes of both viscous displacement of oil by gas and phase exchanges
occurring between oil and gas. Because of the nature of the injected gas (rich
gas from the first separation stage), a condensing/vaporizing process had to be
considered. The SWAG injection speeds up the oil recovery by mobility control
of the water phase. This enhances the sweep efficiency by viscous drive. A
water-blocking effect was found to be negligible because it could be
anticipated due to wettability consideration.
The influence of the fluid description (equation of state, or EOS) and the
three-phase relative permeability model on the simulation results was studied.
An excellent agreement between simulation and production data was obtained with
both gas/oil relative permeability data measured at ambient conditions on a
restored composite core and an appropriate EOS (with seven pseudos). The
condensing/vaporizing process that strips the intermediate compounds from the
oil phase to the gas phase was properly taken into account with this
appropriate EOS. The influence of the three-phase permeability model (either
“geometrical construction” or Stone1) on the results was found to be small.
Introduction
For enhanced oil recovery (EOR) purposes, miscible or immiscible hydrocarbon
gas injections have been applied successfully in many oil reservoirs throughout
the world (Thomas et al. 1994; Lee et al. 1988). Compared to water injection,
gas injection is associated with higher microscopic displacement efficiency due
to the low value of the interfacial tension (IFT) between the oil and gas
phases. IFT tends toward zero when miscibility is reached, which means that the
oil recovery can be total in the swept area. Even when miscibility is not
reached, the mass-transfer mechanisms that occur between oil and gas phases
lead to low IFT values when compared to waterflooding. Even under those
conditions, regarding remaining oil-saturation values, gas injection appears to
be an interesting recovery process.
© 2006. Society of Petroleum Engineers
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History
- Original manuscript received:
18 November 2003
- Revised manuscript received:
6 May 2006
- Manuscript approved:
10 August 2006
- Version of record:
20 December 2006
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