Effect of in Situ Emulsification on Heavy Oil and Water Relative Permeability

Abstract

Abstract The objective of this paper is to provide reservoir engineers fresh insight and a new approach to the description of heavy oil and water relative permeability functions in reservoir simulation. This paper proposes a plausible mechanism of heavy oil flow in porous media influenced by the effect of water-oil emulsification to address the inability of simulation models to replicate primary oil production rates during cold producing operations. A number of heavy oil reservoirs that naturally flow without stimulation show higher field oil production rates than often can be predicted by numerical simulation. To match the field production, reservoir simulation engineers often exhaust all valid parameter changes in the numerical model and resort to questionable changes on parameter values that usually enjoy high confidence level by physical measurements. To overcome these shortcomings, we first identify in situ water-oil emulsification, a plausible mechanism of heavy oil flow in water-oil systems, and then offer a practical approach to modeling water oil relative permeability for heavy oil-water systems. Beyond water-oil relative permeability curve adjustments, the parameters that are changed by simulation engineers during reasonable history matching may consist of an unrealistic increase in oil saturation and/or a significant decrease in oil viscosity. Both parameters are usually measured in labs and should not be altered significantly. In addition, sometimes during simulation model calibration, the increase in absolute permeability goes so high that it cannot be supported by any logic or physical measurement. The new relative permeability modeling approach for heavy oil and water systems considers the fact that naturally occurring heavy oil contains a large quantity of emulsifying agent and the density contrast between heavy oil and water is so low that heavy oil in porous media may flow by a continuous oil and stable emulsion phase. A part of the total oil flow occurs via oil phase that is similar to light oil and water system and the other part flow via a quasi-stable emulsion/water phase. This practical approach for heavy oil water relative permeability modeling removes the difficulties that a simulation engineer often faces during heavy oil water history matching and calibration. The new modeling approach presented in this paper is successfully applied in modeling cold heavy oil production performance for a heavy oil reservoir in California. One field example is provided in this paper and some results are presented to estimate heavy oil water relative permeability from standard lab data.