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Abstract Laboratory evaluation of waterflood behavior of vugular carbonates is subject to significant uncertainty. Even basic parameters such as residual oil saturation are difficult to estimate and depend on experimental conditions. We use X-ray Computed Tomography (CT) scanning to characterize the porosity, permeability, and waterflood displacement behavior in rocks from two carbonate settings. We find that the porosity and permeability distribution are dissimilar. This causes the dependence of their residual oil saturation on water flow rate to be very different. We attempt conventional methods to extract meaningful information from the data but find them inadequate. Introduction The petroleum engineering literature contains few references to multiphase flow studies in vugular carbonates. This is likely due to experimental uncertainties and difficulty in obtaining representative samples. McCaffery et al. reported that waterflood residual oil saturation in carbonates ranges from 15% to 40%, with large variability - due to test conditions, amount of secondary porosity, and initial water saturation. Ehrlich measured drainage relative permeability for vugular, low-permeability samples from the Westerose reservoir. He used the steady state method and full diameter cores. These relative permeability curves had significant plateau regions. Ehrlich attributed this to sequential displacement - - first of secondary porosity that was connected from inlet to outlet; and then of matrix and isolated secondary porosity. MacAllister et al. performed steady-state, water/oil, relative permeability tests on a mixed-wet Baker dolomite (k= 110 md, 22% porosity) core sample using pressure drops of 4 psi and 100 psi. In the 4 psi case, CT images showed that oil and water flow occurred through separate macroscopic regions. This resulted in high relative permeability to both phases. In the 100 psi case, the saturation was more uniformly distributed and the relative permeability values were lower. Narayanan and Deans studied miscible xenon-helium displacement in a full diameter, vugular carbonate sample from Gulf-Connor Fenn-Big Valley, Canada, They concluded that centimeter-scale heterogeneities control flow distribution and that laboratory miscible flood behavior was dominated by convection. Hicks, Jr., Narayanan, and Deans extended this work to study the distribution of porosity and residual oil inside carbonate cores. The Fenn-Big Valley carbonate core was characterized by an exponential drop in frequency with increasing porosity. The San Andres dolomite was characterized by porosity distributed normally about the mean. Waterflood residual oil saturation was 42.6% for the Fenn-Big Valley core and 24.9% for the San Andres sample. We use CT scanning to characterize the porosity, permeability, and waterflood displacement behavior in two different carbonate settings. The first is a high permeability plug sample consisting of vugs embedded in porous matrix rock. The second is a low permeability whole core sample consisting of vugs embedded in dense matrix rock. We investigate the effect of varying flow rate on Sor as the issue of reservoir rate versus high rate flooding is one of persistent concern. Experimental Data Our sample set consists of two vugular carbonate rocks from the Beaverhill Lake formation, Canada. The first is a horizontal plug sample (k=300 md; =14%; L=4.9 cm; D=3.8 cm) and the second is a vertical whole core sample (k=l md; =11%; P. 805 |
