Effect of Temperature on Heavy-Oil/Water Relative Permeabilities in Horizontally Permeabilities in Horizontally and Vertically Drilled Core Plugs Summary Oil/water displacement tests were conducted in preserved core material at reservoir pressure and at various temperatures ranging from room temperature to 522F [272C] to evaluate the effect of temperature on relative permeabilities. Both horizontally and vertically drilled permeabilities. Both horizontally and vertically drilled plugs were tested to determine the influence of flow plugs were tested to determine the influence of flow direction on relative permeabilities and on their temperature dependence. Results show that temperature influences both the endpoint saturations and the endpoint effective permeabilities. Irreducible water saturation increased with increasing temperature, whereas the dependence of residual oil saturation on temperature was less clear-cut. The residual oil saturation appeared to decrease up to an optimum temperature, beyond which the trend reversed. The endpoint effective permeability to oil decreased with increasing temperature, while the endpoint effective permeability to water appeared to be independent of permeability to water appeared to be independent of temperature. The endpoint effective permeability to oil was found to be from one to two orders of magnitude lower in vertically drilled plugs compared with horizontally drilled plugs. On the other hand, endpoint water permeability appeared to be similar in both directions. Introduction Numerical simulation of thermal recovery processes requires data on relative permeability and its dependence on temperature and flow direction. Reliable data of this nature have not been commonly available because of the experimental difficulties involved in measuring relative permeabilities at high temperatures. Often, relative permeabilities at high temperatures. Often, relative permeabilities routinely measured at room temperature permeabilities routinely measured at room temperature are used to predict performance at higher temperatures. In history-matching past reservoir performance, treating relative permeability as an adjustable parameter often becomes necessary. As shown by Dietrich, relative permeabilities measured in unconsolidated sands differ permeabilities measured in unconsolidated sands differ from those required to history-match cyclic steam stimulation results by more than an order of magnitude. Many heavy-oil fields contain discontinuous shale breaks and thin, tight zones that lead to significant differences between vertical and horizontal permeabilities. Since override in the steam injection process can be affected strongly by such barriers, it is desirable to know whether relative permeability curves also show anisotropic behavior and, if so, how this behavior is also affected by temperature. Many investigators have studied the effect of temperature on relative permeability. Edmondson found that residual oil saturation (Sor) decreased with temperature and that changes in water/oil permeability ratio were different with different oils. Poston et al. investigated the influence of temperature on oil/water displacements in unconsolidated sands and concluded that irreducible water saturation increased and Sor decreased with increasing temperature. They also found that relative permeabilities to both oil and water generally increased with increasing temperature. Weinbrandt et al. found that, in Boise sandstone cores, an increase in temperature from room temperature to 175F [79C] resulted in increased irreducible water saturations, decreased Sor, increased endpoint water permeabilities, and increased oil permeabilities. They suggested that thermally induced mechanical stresses may be responsible for some of the observed changes in absolute and relative permeabilities. Lo and Mungan measured water/oil relative permeabilities in Berea sandstone and porous Teflon cores using the steady-state technique at porous Teflon cores using the steady-state technique at temperatures up to about 302F [150C]. They found that the effect of temperature on relative permeabilities was similar in the oil-wet and water-wet systems. They also found that increases in temperature caused decreases in Sor and increases in irreducible water saturation, and suggested that a temperature-induced change in the viscosity ratio may be responsible for the observed changes in relative permeability. In a more recent investigation, Sufi et al. permeability. In a more recent investigation, Sufi et al. found that relative permeabilities determined with clean oil and water in clean Ottawa sand were independent of temperature between 70 and 186F [21 and 86C]. Most of the reported studies on temperature dependence of relative permeabilities have been conducted with clean or extracted core materials and refined oils. JPT P. 1500

A procedure has been developed and tested for evaluating the capillary pressure and wetting properties of rock/fluid systems from unsteady-state displacement data such as that used for calculating two-phase relative permeability characteristics. Currently, the common practice is to conduct most coreflooding experiments so that the capillary pressure gradient in the direction of flow is small compared with the imposed pressure gradient. The proposed method, on the other hand, is based on performing low rate displacements during which capillary forces and, hence, end effects can influence the saturation distribution and pressure response of the core sample. Besides providing a means for monitoring capillary forces and wettability during the dynamic displacement test, the proposed method has the advantage of permitting the displacement tests to be conducted at rates more typical of those in the reservoir. Thus, it is possible to avoid potential problems such as fines migration and emulsion formation, and the method permits a realistic representation of transient interfacial effects that can be important with reservoir fluid systems and chemical flooding agents. Specifically, the method involves performing low rate displacements between the irreducible-water and residual-oil endpoint saturations. Except for the added provision of stopping, restarting, and sometimes reversing the flow after the endpoints have been reached, these are routine unsteady-state displacements in which the standard pressure drop is measured external to the core between the inlet and outlet fluid streams. The dynamically measured capillary pressure properties—besides indicating strong, weak, intermediate, or mixed wettability—then can be used to derive relative permeabilities from the displacement data. Examples of the technique for determining wettability are given for pure-fluids/Berea-sandstone andreservoir-fluids/preserved-reservoir-rock systems. Introduction It long has been recognized that capillary forces can influence the results of relative permeability and oil recovery measurements on core samples.1–5 A scaling criterion for linear displacement tests has been proposed to remove the dependence of oil recovery on displacement rate and system length.5 The objective is to avoid appreciable influence of capillary forces on the flooding behavior that causes a spreading of the displacement front and the well-known end effect or buildup of the wetting phase at the ends of the core. The suggested scaling causes the capillary pressure gradient in the direction of flow to be small compared with the imposed pressure gradient and is expressed asEquation 1 where L is system length (in centimeters), µ is displacing phase viscosity (in centipoise or millipascal-seconds), and q/A is flow rate per unit cross-sectional area (in centimeters per minute). Bentsen6 refined the criterion for neglecting capillary forces to include consideration of the mobility ratio. In related work, Peters and Flock7 recently proposed a dimensionless number and its critical value for predicting the onset of instabilities resulting from viscous fingering at unfavorable mobility ratios. In apparent contrast to the scaling coefficient suggested in Eq. 1, displacements were shown to decline at high flow rates for a given core system and wettability condition.

Three-phase relative permeabilities to water-oil-gas mixtures have been measured both under unsteady- and steady-state conditions through fired Berea sandstone. A computer-based photometric device was used for monitoring fractional flow of displacement fluids. An extension of the Welge-JPN method to three-phase flow was used for the calculation of relative permeabilities from displacement data. Several saturation histories relevant to petroleum reservoir exploitation were examined. Steady-state measurements with saturation histories similar to those in the unsteady-state experiments were made on the same core to enable comparison of the results. Water relative permeabilities were found to depend only on water saturation and were practically independent of the saturation histories considered. Gas relative permeabilities depended on the total liquid saturation; the components of the liquid being of no concern. They depended strongly, however, on the direction of saturation change of the gas phase. Oil relative permeabilities seemed to depend on saturations of all the phases present. Although the direction of oil and water saturation change phases present. Although the direction of oil and water saturation change did not influence oil relative permeabilities significantly, the decreasing gas saturation resulted in higher values as compared to those when the gas saturation was increasing. This seems to suggest that trapping of gas facilitates more free movement of oil. Predictions made by the use of Stone's two models yielded lower values of relative permeability to oil when compared to the experimental results, suggesting the inadequacy of these models even for the strongly water-wet rocks used in the present study. Steady-state measurements of three-phase relative permeability yielded results similar to those obtained by the displacement method for both oil and water. However, owing to a different trapping mechanism, gas phase relative permeability showed a much weaker dependence on the direction of gas saturation change under steady-state conditions when compared to the displacement process. Introduction There are several situations of practical importance in the exploitation of petroleum reservoirs where simultaneous flow of water-oil-gas mixtures is encountered. Waterflooding with free gas present because of prior production by solution gas drive or gas cap expansion drive, alternate water/gas drive, and gas drive with edge-water or aquifer encroachment are but a few examples of this phenomenon. Enhanced recovery methods such as thermal recovery or carbon dioxide immiscible displacement also generate simultaneous flow of three fluid phases. In short, three-phase flow is encountered often enough to warrant a detailed study of the process. Unfortunately, only a few scattered experimental studies have been reported in the literature starting with the one by Leverett and Lewis in 1941, who measured three-phase relative permeabilities in unconsolidated sands by a steady-state dynamic method. Table 1 summarizes, in chronological order, all the experiments reported to date. A detailed account of a literature search is available in another PRI report. As is evident from Table 1, different workers found the three relative permeabilities to depend differently on various fluid saturations. permeabilities to depend differently on various fluid saturations. Donaldson and Kayser have compared the magnitudes of relative permeabilities reported by various workers for water-wet systems and found permeabilities reported by various workers for water-wet systems and found them to deviate from one another so widely that none could be used with confidence in engineering calculations. In the absence of reliable experimental data, reservoir engineers have used theoretical models which make use of such information as capillary pressure or two-phase relative permeabilities to predict three-phase flow pressure or two-phase relative permeabilities to predict three-phase flow behavior. Stone's models which rely on two sets of two-phase data to predict three-phase relative permeabilities, have probably been used most predict three-phase relative permeabilities, have probably been used most widely, but their accuracy of prediction has never been established extensively.

Miscible gas displacement data obtained from full-diameter carbonate reservoir cores have been fitted to a modified miscible flow dispersion-capacitance model. Starting with earlier approaches, we have synthesized an algorithm that provides rapid and accurate determination of the three parameters included in the model: the dispersion coefficient, the flowing fraction of displaceable volume, and the rate constant for mass transfer between flowing and stagnant volumes. Quality of fit is verified with a finite-difference simulation. The dependencies of the three parameters have been evaluated as functions of the displacement velocity and of the water saturation within four carbonate cores composed of various amounts of matrix, vug, and fracture porosity. Numerical simulation of a composite core made by stacking three of the individual cores has been compared with the experimental data. For comparison, an analysis of Berea sandstone gas displacement also has been provided. Although the sandstone displays a minor dependence of gas recovery on water saturation, we found that the carbonate cores are strongly affected by water content. Such behavior would not be measurable if small carbonate samples that can reflect only matrix properties were used. This study therefore represents a significant assessment of the dispersion-capacitance model for carbonate cores and its ability to reflect changes in pore interconnectivity that accompany water saturation alteration. Introduction Miscible displacement processes are used widely in various aspects of oil recovery. A solvent slug injected into a reservoir can be used to displace miscibly either oil or gas. The necessary slug size is determined by the rate at which deterioration can occur as the slug is Another commonly used miscible process involves addition of a small slug within the injected fluids or gases to determine the nature and extent of inter well communication. The quantity of tracer material used is dictated by analytical detection capabilities and by an understanding of the miscible displacement properties of the reservoir. We can develop such understanding by performing one-dimensional (1D) step-change miscible displacement experiments within the laboratory with selected reservoir core material. The effluent profiles derived from the experiments then are fitted to a suitable mathematical model to express the behavior of each rock type through the use of a relatively small number of parameters. This paper illustrates the efficient application of the three-parameter, dispersion-capacitance model. Its application previously has been limited to use with small homogeneous plugs normally composed of intergranular and intencrystalline porosity, and its suitability for use with cores displaying macroscopic heterogeneity has been questioned. Consequently, in addition to illustrating its use with a homogeneous sandstone, we fit data derived from previously reported full-diameter carbonate cores. As noted earlier, these cores were heterogeneous, and each of them displayed different dual or multiple types of porosity characteristic of vugular and fractured carbonate rocks. Dispersion-Capacitance Model The displacement efficiency of one fluid by a second immiscible fluid within a porous medium depends on the complexity of rock and fluid properties. SPEJ P. 647^

For a technically and economically successful miscible project, it is important that the solvent composition be as lean as possible for a given design pressure or that the operating pressure be as low as possible for a given solvent composition. In applying slim tube testing to assess miscibility, oil recovery by itself has historically been considered a sufficient criterion. This paper emphasizes that analyzing other test data, such as effluent gas compositions and pressure drop, are likely more reliable because there can be significant experimental errors associated with evaluating recovery. It is demonstrated that the ambient laboratory condition effluent gas compositions accurately reflect the solvent/oil mixture phase behaviour. In addition, the slim tube pressure drop data can be used to verify miscibility. Thus, by measuring these parameters, one can readily correlate miscibility conditions. It is also demonstrated that on accurately tuned equation of state together with a reliable prediction technique can significantly reduce the number of slim tube displacement tests required to quantify the miscibility conditions. Introduction Economics and solvent supply dictate the selection of miscible gas as an enhanced oil recovery technique. Miscible solvent design criteria, based mainly on oil recovery levels obtained from slim tube displacement tests, have been described in the literature(1,2) for evaluating miscibility. The purpose of this paper is to emphasize that other measured data such as atmospheric flash condition effluent gas compositions and pressure drops are reliable indicators of miscibility and must be included. There are generally two approaches to miscibility design. The first requires determining solvent compositions for a given reservoir pressure and is typically applied to hydrocarbon-based processes. The second approach is to predict a minimum miscibility pressure for a specific solvent composition. This technique is appropriate when considering carbon dioxide, nitrogen, or methane as solvents. An equation of state (EOS), can be used as a predictive tool for miscibility design(3). To use an EOS, it is required that the equation be tuned to accurately match reservoir gas-liquid phase behaviour. That is, the experimentally measured bubble point pressure, (Pb), gas-oil ratio, (GOR), and atmospheric flashed gas and liquid compositions of either a bottom-hole or a recombined test separator reservoir fluid sample must be accurately represented by an EOS. The EOS can then be readily used as basis to predict miscibility conditions. To verify an EOS prediction, two types of laboratory tests can be conducted: static vapour-liquid equilibria (VLE) measurements and/or dynamic slim tube displacement tests(l). Although interpreting VLE test data is usually straightforward, slim tube displacement tests are often misinterpreted by industry. Hence, it is necessary to review the physics occurring during displacement testing, so as to interpret the data from both the fluid phase behaviour and fluid displacement points of view. Terminology Reference to the ternary phase diagram in Figure 1 enables a review of the terminology. This diagram illustrates the phase behaviour existing at a single temperature and pressure. Components are grouped at the three vertices according to whether they are light ends, intermediates, or heavy ends.