The Production Histories of Oil Producing Gas-Drive Reservoirs

Abstract

A theory has been developed for predicting the behavior of solution gas-drive oil producing reservoirs, on the basis of previously established empirical laws on the flow of heterogeneous fluids through porous media. Treatments are given both for the simple pressure depletion history without gas injection, and those for systems in which gas is injected during the course of oil production. The specific results provided by the theoretical analysis include the ultimate oil recovery, and the pressure decline, gas-oil ratio, and productivity factor histories. Two types of gas injection have been considered, namely: (1) that in which the returned gas is supposed to diffuse through and be produced continuously with the oil zone; and (2) that in which the injected gas remains locked in the gas cap, which merely expands as oil production and gas injection proceed. In the latter case the rate of growth of the gas cap is also obtained as a function of the cumulative oil recovery. The theory is illustrated by numerical application to a hypothetical virgin oil reservoir with an original pressure of 2500 p.s.i. producing by gas-drive, and with no initial gas cap. It is so found that if no gas is injected into the system the physical ultimate oil recovery will be 14.5 percent of the pore space, or 27.1 percent of the original stock tank oil content, assuming that the formation initially has a connate water saturation of 30 percent. The gas-oil ratio first declines as production is started, then rises sharply to a maximum of 4400 cu. ft./bbl., and finally falls steeply as the pressure is depleted to atmospheric. If there is no gas segregation and 60 percent of the produced gas is returned to the formation, the ultimate oil recovery will be increased by 27.6 percent. The gas-oil ratio history will be similar to that with no gas injection, but will rise to a maximum of 10,300 cu. ft./bbl. If 80 percent of the gas is returned, the recovery increase will be 48.8 percent, the maximum in the gas-oil ratio history reaching a value of 19,450 cu. ft./bbl. If all the gas is returned, the gas-oil ratio rise will be so rapid that by the time 20,000 cu. ft./bbl. is reached only 23.5 percent additional oil will be recovered. During these operations the productive capacities of the wells will fall by factors of the order of 10, because of the increasing viscosities of the oil and decreasing permeabilities to the oil, as the pressure declines and the oil saturation decreases. For the case where the gas remains trapped in the gas cap, the ultimate oil recovery will be 163 percent greater than by direct pressure depletion, if the residual oil after gravity drainage is 15 percent of the pore space. This recovery will be essentially independent of the amount of gas return, although the final reservoir pressure at the time of complete gas cap expansion will be greater as more gas is returned. The increased oil viscosity and decreased permeability to the oil will here reduce the specific production capacities of the wells to ¼ or ⅓ of their initial values.