Effect Of Relative Permeability On The Numerical Simulation Of The Steam Stimulation Process
Authors: Bennion D.W. , Moore R.G. , Thomas F.B. 
Published: March 2010

Thermal numerical simulators have been used to predict the performance of the steam stimulation processes. Our experience is that room temperature relative permeability curves measured on extracted core samples need to be adjusted to match field performance. This paper describes a study which was conducted to observe the effects of temperature on initial water saturations and residual oil saturations.

A preserved core was mounted, stressed back to reservoir conditions and saturated with live reservoir oil, then waterfloods and oilfloods were run at reservoir and elevated temperatures. Two single-cycle numerical simulations were run. One utilized relative permeability curves derived from a room temperature waterflood on an extracted core which was saturated with mineral oil. The other simulation used the relative permeability curves from the preserved core, which was run with overburden pressure, and live crude oil. Both sets of simulations used temperature functional relationships for the residual oil saturationsand connate water saturations. The simulation which used the preserved core relative permeabilities resulted in matching the field water production much closer than the simulation using extracted core relative permeabilities.

Introduction

Relative permeabilities play an important role in the results of a numerical simulation using a thermal simulator. In thermal processes, the reservoir matrix and fluids undergo temperature changes. These temperature changes reduce the viscosity of the oil, cause rock fluid interactions to occur, and increase stresses within the rock matrix. A number of investigators have found that increases in temperature result in decreases in permeability; Afinogenou (1969). Weinbrandt (1972), and Okoh (l980). Other investigators have found that permeability either increases or remains constant. Gobran (1981) discusses the finding of these investigators. Somerton (1981) has estimated that porosity may decrease as much as 3 to 5 per cent as a result of increasing the temperature by 150 ºC.

Edmondson (1965) found that the residual oil saturation decreases with increases in temperature. Poston (1970) and innokrot (1971) found that as the temperature increased the irreducible water saturation increased. Odeh (l965), Combarnous (1968), Wilson (1956) and Lo (1973) have postulated that the decrease in viscosity ratio is responsible for the decrease in residual oil saturation. Poston (1970) suggested the decrease in residual oil saturation was due to a change in wettability.

Poston (1970) found that for unconsolidated sand both the relative permeability to oil and to water increased as the temperature increased. Weinbrandt (1972) used consolidated Boise sandstone and reported that the relative permeability to oil increased with temperature. The relative permeability to water decreased at low water saturations but increased at flood-out. The study of Lo (1973) using consolidated Berea sandstone and porous teflon cores found that relative permeability to oil and water increased with temperature.

Dietrich (1981) developed a set of empirically derived relative permeability curves to match the performance of a cyclic steam stimulation process in a heavy oil reservoir. To simulate this process both imbibition and drainage relative permeabilities relationships were required. The empirically determined relative permeability curves were very different from those generally reported in the literature for unconsolidated sand.