Three-phase relative permeability plays an important role in the numerical simulation of oil recovery processes. Thermal methods for heavy oil recovery, such as steam drive, in-situ combustion; alternating gas and water injection; and immiscible gas injection in the presence of mobile water involve the simultaneous flow of three immiscible fluids through the porous rock formation at elevated temperatures. Although the importance of reliable experimental data in numerical analyses is well recognized, laboratory measurements of three-phase relative permeability are usually not attempted. The reason for this appears to be the time and expense involved, and the poor reliability of available experimental techniques.
This paper describes an improved laboratory technique which makes the steadystate three-phase relative permeability measurements far less tedious and much more reliable. These improvements have resulted from the application of computer based data acquisition technology and improved methods of controlling several sources of measurement error. The problem of capillary end effects has been virtually eliminated by incorporating an end-effect absorbing section in the design of the core holder. The reliability of differential pressure measurements has been improved by using semipermeable pressure taps and by placing the pressure transducer assembly in a gravity stable position. The reliability of the saturation measurements has been improved by incorporating an in-situ saturation measurement technique based on the electrical resistivity method to supplement the standard material balance measurements. The experimental apparatus has been designed to operate at reservoir conditions, i.e. at elevated temperatures and pressures.
Experiments were conducted with a high viscosity mineral oil, 1% brine and nitrogen gas in an Ottawa sand system to test the apparatus.
The three-phase water relative permeability was found to be a function of water saturation alone. The three-phase gas relative permeability was always lower than the two-phase values and showed some scatter. The oil relative permeability was found to vary with the saturations of the other fluids. Oil isoperms were concave towards the oil apex. Scatter in the data increased with increasing oil saturations. . Experimental results were then compared with predictions obtained using a modification of Stone's method I. The prediction was good at low oil saturations but poor at higher isoperms.
Reservoir engineering calculations frequently require consideration of simultaneous flow of oil, water and gas. Such three-phase flow occurs when oil is displaced by alternating gas and water injection, steam drive, in-situ combustion, and immiscible gas injection in the presence of mobile water. Numerical analyses of such processes require reliable three-phase relative permeability data. Although reservoir simulation programs incorporate one or more estimation techniques which permit three-phase flow studies to be carried out with input of only the two-phase relative permeabilities, such simulations can be no more reliable than the techniques used for estimating three-phase relative permeabilities. Testing the reliability of these estimation techniques is often difficult due to a lack of reliable data on three-phase relative permeabilities.
Although the importance of reliable experimental data in numerical analyses is well recognized, laboratory measurement of threephase relative permeabilty is almost prohibitively difficult.
