This paper examines the effects of alkaline additives on dilute surfactant systems for improved oil recovery. The study was limited to the determination of the effects of alkaline additives on interfacial tension (IFT), surfactant adsorption or retention in Berea cores, and improvement in oil recovery. The alkaline chemicals studied were sodium silicates, sodium phosphates, sodium carbonate, and sodium hydroxide. In addition, optimal salinities and surfactant average equivalent molecular weight for the recovery of two midcontinent crude oils were determined through a combination of IFT determinations and oil displacement tests. The laboratory results show that the alkaline chemicals have two major effects. First, IFT is reduced further by the high pH surfactant/alkali solution combinations, and second, certain alkaline species significantly reduce surfactant retention. This leads to recoveries of residual oil from 40 to 70% with surfactant solutions containing only 0.25 wt% surfactant. Introduction The use of dilute aqueous surfactant systems for enhanced oil recovery has been documented for several decades, but the more pertinent work has been performed in the past 15 years. Gogarty, and Tosch outlined Marathon's early studies on the Maraflood TM process, which employs what is commonly known as a micellar/polymer system for enhanced recovery. In the area of dilute surfactant systems, a considerable body of work has been published in which alkaline chemicals have been added to improve recovery efficiency. A number of processes have been patented in which excess alkaline chemicals have been injected following the initial injection of organic acids. Other systems in which an alkaline preflush preceded the injection of the surfactant slugs have been reported. Similar processes, which can be summarized in a general manner have been reported by several research teams. All these systems are individually different but employ the same general principles in their operation. These principles are as follows.Injection of a sacrificial alkaline chemical, such as sodium carbonate or sodium tripolyphosphate, in a saline solutionto reduce the hardness ion level,to reduce surfactant adsorption or retention, andto provide an optimal salinity for the surfactant slug.Injection of a dilute surfactant slug containing alkaline chemicals, such as sodium carbonate and/or sodium tripolyphosphate, with the proper concentration of sodium chloride added to provide the minimal IFT for optimal oil recovery.Injection of a drive fluid that may or may not contain a polymer additive for increased mobility control. Several field trials of low-tension waterfloods have been reported. In most cases, increased production was observed from watered-out areas. The tests were considered to be technologically successful but not necessarily economically feasible at the time of the test. Some of the disadvantages of dilute surfactant systems can be traced to complex and, in most cases, deleterious effects of hardness ions, mineral surfaces, and highly saline reservoir fluids on the effectiveness of the surfactant in mobilizing the oil phase. Some of these disadvantages can be overcome by proper selection of surfactants that are less sensitive to hardness ions and more tolerant of high salinities. However, most of these surfactant systems are much more expensive than the petroleum sulfonates and still would be subjected to considerable adsorption or retention by the reservoir substrate. Thus, the addition of alkaline chemicals to the surfactant system provides an economical solution that overcomes the adverse conditions mentioned previously. SPEJ P. 503^
This paper is the second of a series of papers reporting our examinations of the effects alkaline additives have on dilute surfactant systems for low-tension waterflooding (LTWF). The first paper outlined the effects on interfacial tension (1FT), hardness removal, and surfactant retention by the core material, and how these parameters then affect overall recovery of oil from watered-out cores containing high-hardness brines. This study examines the effects of those chemicals on permeability, sweep efficiency, and sweep symmetry through multipermeable noncommunicating zones. Correlations and possible mechanisms are offered that relate these findings to the earlier work on surfactant retention and hardness removal.The results of these studies indicate that each alkali behaves differently, but all are capable of enhancing the action of the dilute surfactant treatment. Sweep efficiency in three-dimensional (3D) patterns and sweep symmetry through multi permeable noncommunicating zones is increased by the alkaline chemicals. Selective permeability reduction, caused by the reaction with the residual hardness ions, is suspected as a mechanism. Overall, sodium silicate addition to the surfactant flood as a builder was found to produce the best performance because of its ability to inhibit surfactant retention, thereby increasing the recovery of crude before selective permeability reduction occurs. Overall permeability loss is only about 20 to 25 % in a core initially containing 4,800 ppm of hardness as CaC0 3 under our experimental conditions.
Summary This paper discusses the relative utility of various alkaline inorganic chemicals proposed for waterflooding recovery processes. The chemical properties of these materials are compared, with emphasis on sodium orthosilicate and sodium hydroxide. In addition, laboratory data are presented on interfacial tension (IFT) measurements and relative oil-displacement efficiency of various concentrations of sodium orthosilicate and sodium hydroxide for a low-gravity crude oil. These data were obtained to provide supplementary information for a proposed alkaline waterflooding field trial in the Wilmington field, CA. The laboratory results indicate that significant residual oil recovery from watered-out sandpacks can be obtained by using sodium orthosilicate of a concentration range from 0.2 to 0.6%. Very low recovery yields were obtained with sodium hydroxide at 0.2%, so no further tests were made at higher concentrations because of limitations on the amount of extracted core material available. Introduction Chemicals that yield highly alkaline solutions when added to injection fluids can be used in EOR systems to affect various rock and fluid parameters, such as IFT, viscosity, emulsion stability, rock wettability, fluid mobility, hardness-ion reduction, ion-exchange capacity, surfactant adsorption, phase equilibria, etc., to improve recovery efficiency. The typical chemicals used or proposed for use include the alkaline inorganic compounds such as sodium silicates, sodium hydroxide, sodium carbonate, and sodium phosphates. In alkaline waterflooding of appropriate low-gravity crude oils, oil displacement presumably is initiated by the reaction of alkaline chemicals with acidic substances in the crude oil to form a complex surfactant mixture at the oil/brine interface. To attain low IFT levels, alkaline pH values of at least 11.0 are necessary. The alkaline chemicals that produce the required high pH values at reasonable concentrations are the alkaline sodium silicates, such as sodium orthosilicate, and sodium hydroxide. These two alkaline chemicals exhibit similar interfacial behavior in soft saline solutions; however, hardness ions in the brine can produce a significant difference in their effects on IFT, emulsion stability, rock wettability, and ultimate recovery efficiency. Two alkaline waterflooding pilot field trials are in progress for which dilute saline solutions of sodium orthosilicate are being used as the injection fluid following a soft saline preflush. The first of these trials is being conducted by Aminoil U.S.A. Inc. in the Lower Main zone of the Huntington Beach (CA) field. Laboratory studies comparing the relative recovery efficiencies of sodium orthosilicate and sodium hydroxide for crude oil from this field were reported recently. The second pilot trial is being conducted by the THUMS Long Beach Co. Unit in the Wilmington field. This paper presents laboratory results on IFT measurements and oil-displacement studies performed to provide supplementary information for this field trial. The volumes of preflush, alkaline slug, and postflush used are equivalent to those being used in the field trial. Solution Properties of Alkaline Chemicals Used in Oil-Recovery Systems Alkaline chemicals used in various aspects of EOR include the sodium silicates, sodium hydroxide, sodium carbonate, and sodium phosphates. In solution, these chemicals exhibit significantly different physicochemical behavior toward hardness ions present in reservoir brines, toward crude oils, and toward reservoir rock surfaces. JPT P. 2510^
American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Abstract Alkaline waterflooding has been extensively investigated over the past 50 years in laboratory and field testing situations as a method for increasing crude oil recovery. Alkaline salts such as sodium silicate, sodium hydroxide and sodium carbonate have been cited in various patents and investigations as useful agents for patents and investigations as useful agents for improving water flood performance. Laboratory measurements of interfacial tension (IFT) values between alkaline solutions of sodium orthosilicate and sodium hydroxide and several mid-continent and California crude oil samples have been obtained with a variety of types of injection water. In softened water with no Ca++ or Mg++ ions present, both alkaline salts exhibit similar reductions in interfacial tension with all the crude samples tested. When unsoftened water was used to prepare alkaline injection solutions, sodium orthosilicate was effective in significantly reducing IFT values at concentrations of 0.5% to 1.0% with mid-continent crudes. However, using sodium hydroxide, even up to 5% by weight, IFT values with these same crudes were not reduced as much as with sodium orthosilicate. Both alkaline salts were equally effective in reducing IFT values between the California crude oils tested and unsoftened injection solutions. The concentration of alkaline salt required to produce a minimum IFT value ranged from 0.01% to 0.5% by weight, depending upon the injection water used. This paper will review the laboratory data which has been accumulated, and present a comparison between sodium orthosilicate and sodium hydroxide as alkaline waterflood additives. Introduction A recent article by Johnson provides an excellent review of the historical background, proposed mechanisms and the state-of-the-art proposed mechanisms and the state-of-the-art in caustic and emulsion methods for improved waterflood recovery of oil. The addition of alkaline chemicals to injection water has been proposed by many workers over the past six proposed by many workers over the past six decades (Reference 1 and the references contained therein). Considerable laboratory data and a few field trials have suggested that alkaline waterflooding, or modifications thereof, can provide an incremental increase in oil recovery under the proper operating conditions in selected reservoirs. At the present time there are several field trials of alkaline waterflooding under way or proposed.
Brine displacement studies using Berea sandstone cores were undertaken to compare the effects of alkaline and soft saline preflush systems on an equivalent basis. The alkaline chemicals used were sodium orthosilicate, sodium hydroxide, sodium silicate (2.0 ratio of SiO2/Na2O) and sodium carbonate. The soft saline solutions used ranged in concentration from 3% NaCl to 10% NaCl. The effects of the various preflush systems were measured by titration of the effluent for hardness ion levels. In some of the experiments dilute surfactant was injected following the preflush to determine the effect of surfactant on elution of hardness ions. Results are presented which show that the highly alkaline chemicals, sodium orthosilicate and sodium hydroxide, were very effective in removing the hardness ions from connate brine. Further elution with soft brine following the highly alkaline preflush showed that essentially no ion-exchange occurred and the hardness ion level remained at zero in the effluent. This same effect was observed with the 2.0 ratio sodium silicate, but higher volumes of solution were required to reduce the hardness ion levels to zero in the effluent. With high salinity and sodium carbonate preflushes a high ion exchange peak was observed. Continued elution reduced the hardness ion levels considerably, but not to zero.
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