The Effect of Temperature and Interfacial Tension on Oil-Water Relative Permeabilities in Consolidated and Unconsolidated Porous Media

1990 ◽  
Author(s):  
C.U. Okoye ◽  
A. Hayatdavoudi ◽  
Piya Oungpasuk ◽  
Pin-Hu Wang
Keyword(s):  
Porous Media ◽  
Interfacial Tension ◽  
Effect Of Temperature ◽  
Relative Permeabilities ◽  
Oil Water ◽  
Unconsolidated Porous Media

The Effect of Interfacial Tensions on Relative Oil/Water Permeabilities of Consolidated Porous Media

1982 ◽  
Vol 22 (03) ◽  
pp. 371-381 ◽  
Author(s):  
Jude O. Amaefule ◽  
Lyman L. Handy
Keyword(s):  
Porous Media ◽  
Interfacial Tension ◽  
Relative Permeability ◽  
Residual Oil ◽  
Relative Permeabilities ◽  
Interfacial Tensions ◽  
Oil Displacement ◽  
Oil Water ◽  
Relative Permeability Curves ◽  
Low Tension

Abstract Relative permeabilities of systems containing low- tension additives are needed to develop mechanistic insights as to how injected aqueous chemicals affect fluid distribution and flow behavior. This paper presents results of an experimental investigation of the effect of low interfacial tensions (IFT's) on relative oil/water permeabilities of consolidated porous media. The steady- and unsteady-state displacement methods were used to generate relative permeability curves. Aqueous low-concentration surfactant systems were used to vary IFT levels. Empirical correlations were developed that relate the imbibition relative permeabilities, apparent viscosity, residual oil, and water saturations to the interfacial tension through the capillary number (Nc=v mu / sigma). They require two empirical, experimentally generated coefficients. The experimental results show that the relative oil/water permeabilities at any given saturation are affected substantially by IFT values lower than 10-1 mN/m. Relative oil/water permeabilities increased with decreasing IFT (increasing N ). The residual oil and residual water saturations (S, and S) decreased, while the total relative mobilities increased with decreasing IFT. The correlations predict values of relative oil/water permeability ratios, fractional flow, and residual saturations that agree with our experimental data. Apparent mobility design viscosities decreased exponentially with the capillary number. The results of this study can be used with simulators to predict process performance and efficiency for enhanced oil-recovery projects in which chemicals are considered for use either as waterflood or steamflood additives. However, the combined effect of decreased interfacial tension and increased temperature on relative permeabilities has not yet been studied. Introduction Oil displacement with an aqueous low-concentration surfactant solution is primarily dependent on the effectiveness of the solutions in reducing the IFT between the aqueous phase and the reservoir oil. With the attainment of ultralow IFT's (10 mN/m) and with adequate mobility controls, all the oil contacted can conceivably be displaced. When the interfacial tension is reduced to near zero values, the process tends to approach miscible displacement. However, most high-concentration soluble oil systems revert to immiscible displacement processes as the injected chemical traverses the reservoir. This is a result of the continual depletion of the surfactant by adsorption on the rock and by precipitation with divalent cations in the reservoir brine. The mechanism by which residual oil is mobilized by low-tension displacing fluids cannot be explained solely by the application of Darcy's law to both the aqueous and the oleic phases. On the other hand, in those reservoir regions in which water and oil are flowing concurrently as continuous phases, Darcy's law would be expected to apply and the relative permeability concept would be valid. If a low-tension aqueous phase were to invade a region in which the oil had not as yet been reduced to a discontinuous irreducible saturation, one would expect, also, that the relative permeability concept would be applicable. Under circumstances for which these conditions apply, relative permeabilities at low interfacial tensions would be required, The effect of IFT's on relative permeability curves has received limited treatment in the petroleum literature. Leverett reported a small but definite tendency for a water/oil system in unconsolidated rocks to exhibit 20 to 30% higher relative permeabilities if the IFT was decreased from 24 to 5 mN/m. Mungan studied interfacial effects on oil displacement in Teflons cores. The interfacial tension values varied from 5 to 40 mN/m. SPEJ P. 371^

Effect of Temperature on Heavy-Oil/Water Relative Permeabilities in Horizontally and Vertically Drilled Core Plugs

1985 ◽  
Vol 37 (08) ◽  
pp. 1500-1510 ◽  
Author(s):  
B.B. Maini ◽  
J.P. Batycky
Keyword(s):  
Heavy Oil ◽  
Effect Of Temperature ◽  
Relative Permeabilities ◽  
Oil Water

Effect of Temperature on Two Phase Oil-Water Relative Permeabilities

2015 ◽  
Author(s):  
A.R. Nourmohammad ◽  
A. Vahidi ◽  
M.A. Emadi ◽  
S. Gerami
Keyword(s):  
Effect Of Temperature ◽  
Relative Permeabilities ◽  
Two Phase ◽  
Oil Water

Saturated steam relative permeabilities of unconsolidated porous media

1994 ◽  
Vol 17 (2) ◽  
pp. 105-120 ◽  
Author(s):  
Jean Piquemal
Keyword(s):  
Porous Media ◽  
Saturated Steam ◽  
Relative Permeabilities ◽  
Unconsolidated Porous Media

Effect of Temperature on Heavy Oil/Water Relative Permeabilities

1999 ◽  
Author(s):  
Akin Serhat ◽  
Louis M. Castanier ◽  
William E. Brigham
Keyword(s):  
Heavy Oil ◽  
Effect Of Temperature ◽  
Relative Permeabilities ◽  
Oil Water

Effect of Temperature on Two-Phase Relative Permeabilities of Heavy Oil, Water, Carbon Dioxide, and Methane Determined by Displacement Technique

2013 ◽  
Vol 27 (3) ◽  
pp. 1185-1193 ◽  
Author(s):  
Manoochehr Akhlaghinia ◽  
Farshid Torabi ◽  
Christine W. Chan
Keyword(s):  
Carbon Dioxide ◽  
Heavy Oil ◽  
Effect Of Temperature ◽  
Relative Permeabilities ◽  
Two Phase ◽  
Oil Water

scholarly journals Can Effects of Temperature on Two-Phase Gas/Oil-Relative Permeabilities in Porous Media Be Ignored? A Critical Analysis

Energies ◽  
2020 ◽  
Vol 13 (13) ◽  
pp. 3444
Author(s):  
Saket Kumar ◽  
Sajjad Esmaeili ◽  
Hemanta Sarma ◽  
Brij Maini
Keyword(s):  
Critical Analysis ◽  
Thermal Recovery ◽  
Effect Of Temperature ◽  
Gas Oil ◽  
Relative Permeabilities ◽  
Two Phase ◽  
Recovery Processes ◽  
Fluid Properties ◽  
Oil Water ◽  
Oil Gas

Thermal recovery processes for heavy oil exploitation involve three-phase flow at elevated temperatures. The mathematical modeling of such processes necessitates the account of changes in the rock–fluid system’s flow behavior as the temperature rises. To this end, numerous studies on effects of the temperature on relative permeabilities have been reported in the literature. Compared to studies on the temperature effects on oil/water-relative permeabilities, studies (and hence, data) on gas/oil-relative permeabilities are limited. However, the role of temperature on both gas/oil and oil/water-relative permeabilities has been a topic of much discussion, contradiction and debate. The jury is still out, without a consensus, with several contradictory hypotheses, even for the limited number of studies on gas/oil-relative permeabilities. This study presents a critical analysis of studies on gas/oil-relative permeabilities as reported in the literature, and puts forward an undeniable argument that the temperature does indeed impact gas/oil-relative permeabilities and the other fluid–fluid properties contributing to flow in the reservoir, particularly in a thermal recovery process. It further concludes that such thermal effects on relative permeabilities must be accounted for, properly and adequately, in reservoir simulation studies using numerical models. The paper presents a review of most cited studies since the 1940s and identifies the possible primary causes that contribute to contradictory results among them, such as differences in experimental methodologies, experimental difficulties in flow data acquisition, impact of flow instabilities during flooding, and the differences in the specific impact of temperature on different rock–fluid systems. We first examined the experimental techniques used in measurements of oil/gas-relative permeabilities and identified the challenges involved in obtaining reliable results. Then, the effect of temperature on other rock–fluid properties that may affect the relative permeability was examined. Finally, we assessed the effect of temperature on parameters that characterized the two-phase oil/gas-relative permeability data, including the irreducible water saturation, residual oil saturation and critical gas saturation. Through this critical review of the existing literature on the effect of temperature on gas/oil-relative permeabilities, we conclude that it is an important area that suffers profoundly from a lack of a comprehensive understanding of the degree and extent of how the temperature affects relative permeabilities in thermal recovery processes, and therefore, it is an area that needs further focused research to address various contradictory hypotheses and to describe the flow in the reservoir more reliably.

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