Reservoir Engineering – Laboratory Research - A Practical Utilization of the Theory of Bingham Plastic Flow in Stationary Pipes and Annuli

Many differences can be imagined between gas-oil flow in which the gas is supplied at the face of the core and gas-oil flow in which the flowing gas was originally dissolved in the oil. If capillary pressure characteristics and flow requirements control gas saturation distribution, the gas would be expected to be located at preferred sites within the porous medium as determined by pore sizes. On the other hand, during solution gas drive the gas first appears as bubbles through a nuclea-tion process. Nothing in self-nucleation theory specifies at which sites the first bubbles should be formed. In all probability they will be randomly distributed throughout the porous medium. Furthermore, it is not at all certain that even at low rates of production the gas will redistribute itself after nucleation to the channels normally occupied by gas in simple gas flow. Stewart, et at, have shown that at least for some limestone samples, oil recoveries could not be predicted for all rates of production using any one set of relative gas and oil permeabilities. An important factor in controlling recoveries during solution gas drive was the rate of bubble formation, higher rates giving higher recoveries. Stewart, et al, attributed the increase in recovery to a better distribution of the gas phase in heterogeneous limestone samples than is obtained by simple external gas drive. Differences in recovery from these causes were not reported for sandstone cores. In the experiments to be reported here, oil recovery, pressure and producing GOR history were measured during solution gas drive for a 5-ft sandstone core. The results were compared with predictions from the Muskat method for computing solution gas-drive behavior using external gas-drive relative permeability. The effects of changing the rate of production and oil viscosity were studied. At high laboratory rates of average pressure decline, two observations were made which would not have been predicted by Muskat's depletion theory: (1) oil recovery increased with increasing rate of production for a given viscosity oil, and (2) oil recovery increased with increasing oil viscosity for a given high rate of production. Both of these observations are explained as consequences of diffusion control of gas saturations superimposed on the normal gas-oil flow requirements, Fur- thermore, discontinuous gas phase flow appears to be significant during solution gas drive. The laboratory tests were performed at rates of average pressure decline many times greater than the maximum possible rate of average pressure decline in an actual oil field. It is, therefore, not possible to draw any direct conclusions regarding the effect of rate on recovery for the solution gas-drive mechanism under actual field conditions. However, at the lower laboratory rates, recoveries were nearly independent of rate and could be predicted by the Muskat method, using external gas-drive relative permeability data. These results suggest that at normal oilfield rates the effect of rate on recovery for the solution gas-drive mechanism is negligible. EXPERIMENTAL PROCEDURES The core material for the pressure depletion studies was Bandera sandstone from an outcrop in the Mid-Continent. This sandstone was selected because of its low permeability (about 10 md), which would permit the development of substantial pressure gradients in the corn at moderate flow rates. The core was 5-ft long and 2-in. in diameter. Its properties are listed in Table 1. Relative gas-to-oil permeability ratios were measured by an external gas-drive method2. The results are shown for a short 2-in. core and for the 5-ft core in Fig. 8. Oils used in the pressure depletion experiments were kerosene and a highly refined white oil (standard white oil No. 3) with gas-free viscosities of 1.8 and 25 cp, respectively. The gas was a naturally occurring methane from Gough field, Inglewood, Calif. The oil viscosities, gas solubilities and formation volume factors are plotted as functions of pressure at 75°F in Figs. 1 and 2. Methane viscosities and compressibilities were obtained from the literature"'. A core mounting was required which could withstand up to 2,500 psi internal pressure. This was obtained by first encasing the core completely in a plastic resin (Scotch Cast, manufactured by Minnesota Mining & Manufacturing Co.) The plastic covered core was then inserted into a steel pipe equipped with screw caps so that the plastic coating could be pressured from