Multi-phase Well Testing to Calibrate Relative Permeability Measurements for Reservoir Simulation (SPE 154851)

Special core analysis (SCAL) is the standard method for estimating relative permeabilities. These, however, must be upscaled for reservoir simulation and the upscaling process creates uncertainties that are propagated to field performance forecasts. This paper describes a six-stage well testing procedure to calibrate relative permeabilities for reservoir simulation and to reduce uncertainties in relative permeability end points and curvature. The well test includes: (1) single phase oil production; (2) build up; (3) single phase water injection; (4) falloff; (5) two-phase oil and water production; and (6) a final build up. The final build up is initiated at minimum well productivity. Transient pressure analyses of the first build up (2) and the fall off (4) provide the single phase mobility for each fluid at respective saturation end points. These yield an estimate for endpoint water relative permeability using a Corey type relative permeability correlation. Analysis of the second build up (6), on the other hand, yields an estimate of the minimum mobility. Uncertainty in oil and water relative permeability curvature (which depends on Corey exponents) is reduced using all three mobility estimates, while uncertainty in end point saturations can be reduced by running wireline logs at the onset of the test and of the following injection. The procedure is demonstrated by simulating a newly drilled well in an oil-water homogeneous reservoir above the bubble point pressure. The impact of relative permeabilities on water breakthrough and and oil production is shown to be significant in such an oil field developed by water flood. Sensitivities to reservoir heterogeneity, water cut during the flow back period, numerical dispersion, and capillary pressure have also been explored. Information provided by the proposed test and interpretation procedure allows improved field development decisions early in field life.