Primary gas recovery for a volumetric reservoir ends when the reservoir pressure declines below the value required to flow gas to the surface at the sales line pressure. Secondary gas recovery techniques can then be employed to increase the recovery, once they are economically viable. The most common of these techniques is gas compression; but another feasible technique, which is rarely ever explored, is water injection. This paper evaluates the incremental benefit of water injection in a conventional gas reservoir when compared to gas compression.

This was achieved through analytical simulation of a retrograde gas-condensate reservoir located in the Columbus Basin off the south-east coast of Trinidad. The techniques which were applied here have been historically used in the waterflooding of oil reservoirs, and were tailored in this novel case for the use in gas reservoirs. The reservoir evaluated is a faulted sandstone formation of good quality that is divided into two hydrocarbon bearing segments. In one of the segments, production ended due to a decline in the reservoir pressure, indicating the end of primary gas recovery. Both reservoir and well modelling were done using the IPM Suite. In this paper, the scope was narrowed to focus on the application of analytical simulation as a means of quickly screening various production scenarios. Simple economic evaluations were done using the University's methodology and current economic metrics, with the operational and capital expenditures derived from offshore projects by operator companies within Trinidad.

The findings showed that while gas compression generated significantly higher internal rates of return, water injection provided similar net cash flows. Unlike gas compression, which improves the recovery by allowing the reservoir to produce at a lower tubing head pressure than the sales line pressure; water injection increases the reservoir pressure by filling the voidage space created as a result of the depletion process. Thus, the feasibility of water injection is dictated largely by the volume of water which is required, since gas is highly compressible.

The primary value of water injection as a secondary gas recovery technique stems from the use of high water rates from nearby producing wells under aquifer drive, which would otherwise be shut-in. The technique can also be managed as a water disposal option for adjacent fields, thus reducing company expenditure on treating the produced water from the wells mentioned above.

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