The Effect of Temperature on Irreducible Water Saturation and Relative Permeability of Unconsolidated Sands
Authors: Poston S.W. , Ysrael S. , Hossain A.K.M.S. , Montgomery E.F. 
Published: December 2007

Poston, S.W., Junior Member AIME, Nigerian Gulf Oil Co., Lagos, Nigeria Ysrael, S., Shell Oil Co., Los Angeles, Calif. Hossain, A.K.M.S., Junior Member AIME, Saudi Arabia Oil Ministry, Dhahran, Saudi Arabia Montgomery III, E.F., Junior Member AIME, Shell Oil Co., New Orleans, La. Ramey Jr., H.J., Member AIME, Stanford U., Stanford, Calif.

The injection of hot fluids into an oil reservoir has become an important oil recovery process in the last few years. Numerous publications have considered the estimation of oil displacement under hot water or steam injection. None have considered the potential effects of temperature level upon relative permeabilities under immiscible displacement. In view of the work of Corey, Wyllie and Garaner, and Naar and Henderson, it appears reasonable to expect some sort of change in relative permeability with temperature change because the residual oil saturation depends upon temperature level. To investigate this possibility, isothermal water-oil displacements were carried out at various temperature levels with two unconsolidated sands. Both a natural oil sand and a clean quartz sand were used. Three oils were used having viscosities at room temperature of 80, 99 and 600 cp. Temperature level varied from 70 degrees F to approximately 300 degrees F. Initial saturations were established by displacing a core containing 100-percent deaerated water to a practical, irreducible water saturation with oil. Initially, this was done at room temperature for all runs. But it was observed that only oil was displaced from the core by thermal expansion upon heating to run temperature. Additional runs were made by establishing irreducible water saturation at the elevated run temperature. This indicated a significant increase in irreducible water saturation with temperature increase for some systems. A study of the effect of temperature level upon both oil-water contact angles and interfacial tension was made. The result indicated that, although interfacial forces decreased with temperature increase, oil-water-solid systems studied became more water-wet with temperature increase. After establishing saturations, the core was displaced with water isothermally at various temperature levels in succeeding runs. Results were used to compute oil and water relative permeabilities at various temperature levels. Results indicated important increases in both oil and water relative permeabilities as temperature increased. The Johnson-Bossler-Naumann dynamic relative permeability determination method was used. Although studies were carried out for a limited number of oils in unconsolidated sands, it appears that relative permeabilities may depend markedly upon temperature level.

Introduction

Recently, the injection of hot fluids into an oil reservoir has become an important oil recovery process. Due to the relative newness of the method and potential competitive advantage, few technical studies have been published. Most of the publications concerning hot fluid injection have dealt either with the results of field tests or with the gross heat transport involved with this type of fluid injection. The first detailed study of the injection of hot fluids into an oil reservoir was published in 1961 by Willman et al. They presented experimental results of cold water, hot water, and steam injection into consolidated sandstone cores to displace oil. The authors postulated the oil displacement mechanism involved in hot fluid injection and advanced a design method. The method involved the assumption that relative permeability was independent of temperature.

SPEJ

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