Prediction of Polymer Flood Performance

Patton, J.T., Member AIME, Patton, J.T., Member AIME, Computer/Bioengineering Institute, Inc., Houston, Tex. Coats, K.H., Member AIME, International Computer Applications Ltd., Houston, Tex. Colegrove, G.T., Kelco Co., Houston, Tex. Abstract This experimental and numerical study was performed to estimate the incremental oil recovery performed to estimate the incremental oil recovery by pattern polymer flooding in a California viscous-oil reservoir. Results indicate that adding 270-ppm Kelzan to the normal flood water will boost oil production by 42 percent (at 1 PV injected) and production by 42 percent (at 1 PV injected) and will reduce water handling costs sharply. This corresponds to $8.35 incremental oil/$1.00 polymer injected, taking into account the 30 percent pore volume bank of polymer solution. The 28.6 percent additional oil recovery predicted at 0.5 PV injected yields a return of $4.60 incremental oil/$1.00 polymer injected. polymer injected. The field predictions are based onlaboratory measurements of polymer solution viscosity, adsorption and dispersion upon displacement by normal water in a sand representative of the reservoir,linear laboratory oil displacement experiments using brine and polymer solution, anda numerical model developed to simulate linear or five-spot polymer floods in single-layer or stratified reservoirs. The paper presents an analytical solution to the linear polymer flood problem, which provides a check on accuracy of the numerical model and a quick estimate of additional oil recovery by line-drive polymer floods. The numerical model developed indicates that additional oil recovery by polymer flooding is sensitive to polymer bank size polymer flooding is sensitive to polymer bank size and adsorption level and is insensitive to the extent of dispersion active at the trailing edge of the polymer slug. polymer slug Introduction The benefits of improving the mobility ratio, lambda o/lambda w, on waterflood performance is well documented and research on how best to effect this improvement has been considerable. Both producers and chemical manufacturers, spurred on producers and chemical manufacturers, spurred on by the vast reserves of oil which will be otherwise abandoned, have sought to resolve the problem. Currently, two types of additives are being marketed and field tested with promising results. Both additives increase oil recovery by lowering the mobility of the flood water, lambda w. However, they effect this lowering by distinctly different mechanisms. Mobility of the flood water is given by: lambdaw = kw/ w . Hence, one may elect to either increase viscosity, mu w, or decrease effective permeability, kw. Viscosity can be increased by adding small amounts of a water-soluble polymer. To be effective at the flood front this additive should exhibit minimum adsorption on the pore surfaces. Polymers showing minimal adsorption are generally a combination nonionic-anionic type. The negative charge repels the clay platelets to reduce adsorption and the nonionic portion provides the brine tolerance required for reservoir applications. A polymer of this type, Kelzan M, was chosen for the study. The alternate method of lowering mobility is equally well known. It consists of adding to the flood water a polymer designed to adsorb on the pore surfaces, thereby physically reducing the available flow area. This study was performed to estimate the additional oil recovery by pattern polymer flooding using Kelzan in a California viscous-oil reservoir. Laboratory experiments were performed to estimate polymer solution viscosity, adsorption and polymer solution viscosity, adsorption and dispersion upon displacement by normal injection water. Waterflood and polymer flood oil recovery curves were obtained for a laboratory core packed with sand representative of the reservoir. A numerical model was developed to simulate polymer floods in linear or five-spot patterns in single-layer or stratified reservoirs. An analytical solution to the linear polymer flood problem was developed to provide a quick estimate of incremental oil provide a quick estimate of incremental oil obtainable by polymer flooding and to provide a check on the accuracy of the numerical model. SPEJ P. 72

The Effect of Temperature on Irreducible Water Saturation and Relative Permeability of Unconsolidated Sands

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. Abstract 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 P. 171ˆ

Interfacial Tension of the Methane-Normal Decane System

STEGEMEIER, G.L., JUNIOR MEMBER AIME, SHELL DEVELOPMENT CO., HOUSTON, TEX. PENNINGTON, B.F., JUNIOR MEMBER AIME, HUMBLE OIL AND REFINING CO., HOUSTON, TEX., BRAUER, E.B., JUNIOR MEMBER AIME, UNION OIL CO., ABBEVILLE, LA., HOUGH, E.W., U. OF TEXAS, AUSTIN, TEX. Abstract Interfacial tension divided by the difference in density between the liquid and the vapor phases was determined experimentally by the pendant drop method on several isotherms in the two phase region below the critical point for the methane-normal de can e system. The density difference data of Sage and Lacey was used in the calculation of inter facial tension. Both inter facial tension and interfacial tension divided by density difference were found to vanish at the critical point. Interfacial tensions of less than one dyne/centimeter were observed as far as 1,000 pounds per square inch below the critical pressure. EXPERIMENTAL PROCEDURE The interfacial tension divided by the density difference for the methane-normal decane system was determined at the 100 degrees, 130 degrees, 160 degrees and 190 degrees F isotherms, from pressures of about 1,000 psi to the critical pressure, which is more than 5,000 psi for these isotherms. Particular emphasis was placed upon the investigation at pressures slightly below the critical pressure where the interfacial tension is less than 0.5 dyne/cm. Volumetric properties in the two-phase region, including the critical pressures and temperatures, were taken from the work of Sage and Lacey. The experimental pendant-drop technique used for the determination of interfacial tensions at high pressures incorporated the ideas of Michaels and Hauser, Hough, et al, Walker and Heuer. In addition, the technique for determination of extremely small interfacial tension by Jennings was utilized in the region near the critical points. A detailed description of the apparatus is given in a dissertation by one of the authors. Cleaning operations on the stainless-steel sample system included successive washings with chromic acid, tap water and, finally, distilled water. Subsequent cleanings were performed with re-distilled normal pentane, which had an extremely low residue upon evaporation. Specific composition requirements necessitated a fairly precise sample introduction although, for a two-phase, two-component system, the composition of each phase is completely determined if pressure and temperature are controlled. The normal decane was delivered into the evacuated sample system as a liquid from a burette. The methane was then introduced into the system from a calibrated isothermal container, so that pressure differentials could be used to determine the amount introduced. High pressures were obtained by compressing the sample with a mercury injection pump until the critical pressure was reached for the particular isotherm being studied. Experimental data were then obtained for specific pressures by first decreasing the pressure slightly so that two phases would appear, and then photographing a drop at that pressure. Subsequent photographs were made at increments throughout the pressure range. SPEJ P. 257^