Abstract A comprehensive numerical study was conducted to quantify the effects of endpoint saturations and relative permeabilities on steamflood performance for a heavy oil reservoir. Results show that the region most important for performance prediction is the high-temperature, gas (vapor)-oil relative permeability near the residual oil saturation permeability near the residual oil saturation (S). Furthermore, gas-oil relative permeabilities should be measured at steam temperatures permeabilities should be measured at steam temperatures because gas displacement occurs at steam conditions. For the water-oil system, irreducible water saturation (S) has a greater effect on performance than residual oil saturation to water (S) performance than residual oil saturation to water (S) and the effect of temperature-dependent endpoint saturations is small.
The linear interpolation model (SPE 17369) for three-phase oil relative permeability is preferable over the Stone's II model because it more accurately predicts residual oil saturation to steam. "Practical" endpoint oil saturations are adequate for performance prediction because very low values of oil relative permeability do not significantly affect recovery calculations. A 15% change in Sorg, Swir, and Sorw resulted in a 26, 13, and 7% change in cumulative oil recovery, respectively.
Introduction For specified operating conditions, steamflood performance predicted by numerical models is performance predicted by numerical models is dependent upon (1) the numerical simulator used, (2) reservoir geology and initial conditions, and (3) process modeling parameters. Results are strongly affected by known process variations, such as variation in steam quality, water injection after steam injection, and injection of inert gas with steam.
Most commercial thermal simulators including Chevron's SIS3 are three-dimensional, multi-phase, and compositional. Therefore, it is assumed here that simulator limitations do not include these. Simulator parameters that do affect predictions include the finite difference scheme used to represent the governing equations (i.e., 7-point vs. 9-point, etc.) and the use of parallel vs. diagonal grid. Parallel grids are generally used in thermal simulations' because they more closely predict the breakthrough times and they depict predict the breakthrough times and they depict steam tongue observed in three-dimensional, scaled laboratory models.
Reservoir geology and initial conditions, of course, strongly affect performance. These include saturations (oil, water, and gas), permeability, porosity, and their distributions. In addition. porosity, and their distributions. In addition. shale continuity and the presence of gas cap or aquifer also strongly influence performance. In general, geology is assumed to be known a priori for simulation studies. Incorrect geological representation can result in unpleasant surprises.
For a given simulator and known reservoir geology, endpoint saturations and relative permeabilities affect the performance most among the various input process modeling parameters. They affect process modeling parameters. They affect cumulative oil recovery, oil production rate, and produced fluid ratios. Other modeling parameters produced fluid ratios. Other modeling parameters that can affect predicted performance include wellbore fluid segregations and grid size.
Field measurement of residual oil saturation in the steamflooded zone are often lower than those measured in the laboratory. The higher residual oil saturation measured in the laboratory may be caused by inaccurate measurement or, more likely, they may not be the "true" residual oil saturation.
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