Numerical Simulation of the Effect of Critical Gas Saturation and Other Parameters on the Productivity of Methane From Geopressured Aquifers

Abstract

Summary A numerical simulation study has shown that critical gas saturation is one of the most significant parameters that controls the productivity of methane from geopressured aquifers. Ultimate fluid production from such reservoirs is restricted by insufficient gas in solution to maintain the reservoir pressure. Introduction Geopressured aquifers in the U.S. gulf coast area have received wide publicity as a possible major source of methane. Geological and geophysical studies have indicated suitable reservoirs over a wide area of southern Texas and Louisiana. The economics of methane recovery from geopressured aquifers has been questioned by studies such as that by Doscher et al. A detailed reservoir modeling study was conducted to predict performance characteristics of these reservoirs. In particular, sensitivity studies were made to determine effects of various parameters, that might enhance the economic production of methane from such reservoirs. Physical Properties of the Reservoir and the Brine The geopressured brine studied in this work is saturated with methane at 11,000 psia (75 840 kPa) and 240 degrees F (116 degrees C). The PV properties of the brine are shown in Figs. 1 through 4. The solubility of methane in pure water is a function of both pressure and temperature. Over the pressure range of geopressured reservoirs. the solubility increases with temperature. For the temperature range assumed in this study, a maximum solubility of 34 scf/STB (6.05 std m3 /stock-tank m3) in the 30,000-ppm brine is expected. The available FVF data for water were extrapolated to the required higher pressure range. For the studied range of pressures, Bw varies from 1.037 to 1.045 RB/STB (res m3/stock-tank m3) (Figs. 2 and 3). FVF increases only slightly with gas saturation (Fig. 3). The viscosity data used for brine 4 are shown in Fig. 4. The effect of dissolved hydrocarbon gases in water is not known, but it is not believed significant because of the very low solubility of methane. One significant change was made in the assumed properties of the reservoir since the conclusion of the earlier study; the compressibility was reduced by a factor of two, to 5 × 10 -6 psi -1 (7.3 × 10 -7 kPa -1). This lower value was chosen because, as Geerstma concluded, the effective value of compressibility should be of the order of one-half that measured in the laboratory under triaxial loading. Although no laboratory data on the compressibility of cores from geopressured reservoirs are available in the literature, 1 0 × 10 -11 psi 1 (1.5 × 10 - 6 kPa is the highest value for most reported laboratory measurements. Description of the Reservoir Model The numerical model used is essentially the four-component model developed by ARCO Oil and Gas Co. and has been described elsewhere. The object code was loaned to the U.S. of Southern California. Through the input data, various options as to the dimensional configuration of the reservoir and the use of either a four-component or a black-oil system could be exercised. A 9×9×1 areal grid was used to simulate the performance of a typical well draining a 40-sq mile (103.6-km2 ) area. The number of phases was scaled down to a gas phase (methane) and a liquid phase (brine) by manipulation of the input data. This was accomplished by the adjustment of the relative permeabilities, capillary pressure curves, and the PVT data such that the oil phase and the water phase had identical properties. JPT P. 1880^