Experimental Verification of a Modified Scaling Group for Spontaneous Imbibition
- Xiaoyun Zhang (U. of Wyoming) | Norman R. Morrow (U. of Wyoming, Western Research Institute) | Shouxiang Ma (Western Research Institute)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- November 1996
- Document Type
- Journal Paper
- 280 - 285
- 1996. Society of Petroleum Engineers
- 4.1.2 Separation and Treating, 5.8.6 Naturally Fractured Reservoir, 4.3.4 Scale, 1.6.9 Coring, Fishing
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Spontaneous imbibition is of critical importance to oil recovery from fractured reservoirs. A widely used approach to prediction of oil recovery involves scale-up of laboratory results to reservoir conditions. Scaling involves the effects of sample size, shape, boundary conditions, viscosity and viscosity ratios, interfacial tension, pore structure, wettability, capillary pressure and relative permeability. This work addresses the problem of scaling the combined effects of sample shape, boundary conditions, and viscosity ratios with only minor variations in other parameters.
Imbibition measurements are presented for cylindrical Berea Sandstone cores of different lengths. For some experiments, core surfaces were partially sealed with epoxy to give different boundary conditions. Cores were initially saturated with refined mineral oils of different viscosities. A synthetic reservoir brine was used as the wetting phase. A characteristic length was defined as the square root of the ratio of volume to the summation of the ratios of area of core surface open to imbibition to the corresponding distance from the surface to the no-flow boundary. The characteristic length, in combination with a term that compensates for the effect of viscosity ratio, gave close correlation of all data.
Spontaneous imbibition is an important phenomenon in oil recovery from fractured reservoirs where the rate of mass transfer between the rock matrix and the fractures determines the oil production. Imbibition is also important in evaluation of wettability of fluid/liquid/porous media systems. The rate of imbibition is primarily dependent on the porous media, the fluids, and their interactions. These include matrix permeability and relative permeabilities, matrix shapes and boundary conditions, fluid viscosity, interfacial tension and wettability. Laboratory results need to be scaled to estimate oil recovery from reservoir matrix blocks which have shapes, sizes, and boundary conditions very different from those of the laboratory core samples.
A shape factor, proposed by Kazemi et al. to compensate for the effect of size, shape, and boundary conditions of the matrix on scaling of mass transfer between matrix and fractures, has been applied in numerical simulation of fractured reservoirs. This shape factor was later modified by Ma et al. based on data reported by Hamon and Vidal. By considering the effect of core sample size, boundary conditions, and viscosity ratios, a generalized scaling group was proposed. Additional experimental data are needed to verify this generalized scaling group.
The main concern of this work is correlation of imbibition recovery curves for the effect of core sample size and boundary conditions. Results on the effect of viscosity ratio on imbibition rate are also presented.
The Scaling Equation. The basic requirements for scaling of laboratory data to field conditions were investigated by Rapoport.
|File Size||444 KB||Number of Pages||6|