Accurate drainage and imbibition relative permeability data are essential for the accurate prediction of the performance of heavy oil reservoirs undergoing cyclic steam stimulation or steam drives. There is very little published data regarding steady state relative permeability measurements at elevated temperatures. This paper documents two complete water-bitumen steady state drainage and imbibition tests conducted at a temperature of 200 °C at full reservoir pressure and overburden conditions utilizing composite core stacks of actual, preserved reservoir core material. The test results indicate substantial hysteresis effects in the non-wetting (bitumen) phase and provide insight into the wettabillty, displacement efficiency, residual saturations and endpoint permeabilities and relative permeabilities for an unconsolidated heavy oil sandstone reservoir.
Relative permeability Is an empirical parameter used to modify Darcy's single phase flow equation to account for the numerous complex effects associated with the flow of multiple immiscible phases within porous media1.
Relative permeability measurements are utilized extensively in many areas of reservoir engineering, and more particularly in recent years In the area of matching, predicting and optimizing reservoir performance and depletion strategies through the use of detailed numerical simulation models. Those Involved In numerical simulation realize the importance of good relative permeability data on the performance of reservoir simulation models. This paper discusses the generation of two complete sets of high temperature drainage and hysteresis relative permeability data.
Relative permeability can be affected by many physical parameters including fluid saturations.2–4 physical rock properties,5–7 weltability,5–10 saturation history (hysteresis effects, 15–16overburden stress,13–14 clay and fines content,13–14 temperature,17,18 interfacial tension,19 viscosity 20 magnitude of Initial phase saturations,21–22 Immobile or trapped phases,21–22 and displacement rates and capillary outlet phenomena.23–26. A detailed discussion of the many factors affecting relative permeability is beyond the scope of this paper, but the general consensus of researchers is that In order to obtain the most representative relative permeability data that reservoir conditions during the tests be duplicated as closely as possible. This involves the use of well preserved or restored state reservoir core material, the use of uncontaminated actual reservoir fluids in the tests, and operation at full reservoir conditions of temperature, pressure and confining overburden stress.
Various authors have investigated the effect of temperature on absolute fluid permeability. Gobran14 investigated the effects of temperature on the permeability of both consolidated and unconsolidated sands and found only moderate differences in permeability in the 38 to 149 °C temperature range.
Udell et al27 investigated high temperature absolute permeabilities in glass bead and Silicon sand packs and found substantial permeability reductions (up to 40%) at temperatures exceeding 150 °C. They concluded that these permeability reductions could be attributed to stress and temperature Induced Silica dissolution at the grain contacts and used effluent analyses which contained large amounts of dissolved silica to support these findi
