In the past several years, there has been renewed interest in enhanced oil recovery (EOR) by alkaline injection. Alkaline solutions also are being used as preflushes in micellar/polymer projects. Several major field tests of alkaline flooding are planned, are in progress, or recently have been completed. Considerable basic research on alkaline injection has been published recently, and more is in progress.This paper summarizes known field tests and, where available, the amount of alkali injected and the performance results. Recent laboratory work, much sponsored by the U.S. DOE, and the findings are described. Alkaline flood field test plans for new projects are summarized.

Summary Alkaline chemicals in enhanced recovery operations are used (1) as preflush agents, (2) with polymers and surfactants, and (3) as a principal recovery agent. In these chemical flooding techniques, the precipitation reactions of multivalent hardness ions with alkalis are of particular concern. These reactions may be prevented at the injection wells through adequate preflushing and/or the use of good-quality softened water; filtration can remove any precipitates that form at the surface. In the formation, precipitates that form at the surface. In the formation, many reactions occur that alter the injected slug significantly. Those include dissolution, mixing, neutralization, and ion exchange. Such reactions may lead to beneficial fluid diversion as precipitates form and block high-flow channels. At the producing wells, however, precipitation and deposition phenomena are undesirable because scales may form that restrict production and foul well equipment. With the current higher production and foul well equipment. With the current higher concentrations of alkali being used in the field, the development of well scaling has become noticeable and difficult to control by previously accepted practices. This paper describes the progress and experience gained at the Long Beach Unit, Wilmington, CA, alkaline pilot dealing with scales formed in producing wells. These scales have been made up variously of calcium carbonate, magnesium silicate, and amorphous silica. In particular, the reservoir characteristics and chemical conditions leading to the scale formation are discussed in detail, showing what, how, and why the scale forms. For the Wilmington alkaline pilot, the cause appears to be the mixing of very hard waters from one subzone with moderately alkaline water from other subzones. This mixing and the dissolution of formation solids by the alkali have led to scale formation in the producers closest to the injectors. producers closest to the injectors. A few general scale inhibitor formulations, useful for both formation squeeze treatments and continuous sidestream annular injection, have been effective in controlling the carbonate scale under laboratory and field conditions. However, the physical environment and mechanical limitations in the field have resulted in a new deposit, consisting mainly of amorphous silica, against which the current inhibitor systems am ineffective. We suggest field procedures for dealing with such a situation. It is anticipated that the use of appropriate chemicals and methods can lead to cost-effective scale control. Introduction Them is a large body of literature on alkaline flooding and its variations. However, few authors consider associated scale phenomena at the production wells or in laboratory studies, although it is well known that alkaline chemicals react with reservoir rock and fluids to produce precipitates. Mungan mentions briefly that produce precipitates. Mungan mentions briefly that plugging and scaling were noted in some field-test plugging and scaling were noted in some field-test production wells but gives no details. Raimondi et al. production wells but gives no details. Raimondi et al. describing a sodium hydroxide pilot in the North Ward-Estes field, observed increased gypsum scale formation in producers. This reservoir has a high gypsum content. However, no treatment was discussed. The authors also noted an increase in silica content at the producers but did not detect an accompanying increase in pH value or decrease in hardness levels in the produced fluids. The alkaline slug was believed to have been completely consumed by inaction with gypsum. In a field test at the Trekhozernoye deposit in Russia, fluid-flow diversion was reported because of swelling and migrating clays and precipitation of calcium and magnesium carbonates. The produced fluids showed a decrease in Ca++ ion with subsequent increases in HCO3 - ion. In laboratory tests evaluating alkaline flooding for an Alberta reservoir, Novosad and McCaffrey reported a white precipitate in the coreflood effluents that added to the alkali consumption. They also noted that silicates are more effective at precipitation divalent metal ions. Sydansk observed the formation of new, highly hydrated alumina-silicate precipitates in alkaline com tests; these have lower silica/alumina ratios than the original formation clays. Carbonate minerals in the core dissolved first, leading to accelerated alkaline consumption. Significant amounts of silica were dissolved from the rock matrix at elevated temperatures. A number of other studies show that alkalis react strongly with the various reservoir-rock constituents. These inactions can produce very complex ionic effluents downstream in both laboratory com tests and field production wells. Ehrlich and Wygal studied the caustic consumption of a number of clays and minerals in an attempt to quantify the contribution of each to the overall consumption. More recently, this quantification has been extended by Mohnot et al. Holm and Robertson studied the effect of various preflush agents, including alkaline silicates on divalent ion exchange in surfactant flooding. JPT P. 1466

This paper describes the results of a series of tertiary, immiscibie, CO 2 corefloods of Wilmington field Pliocene reservoir rock containing heavy oil (± 14 ° API [±O. 97 g/cm 3] and ±480 cp [±480 mPa' s]). An initial set of corefloods defined the recovery potential of the CO 2 injection, while a series of later tests served to define the process more accurately as applIed III the field. In an attempt to understand the displacement mechanism, simulator matching of one of the later, more refined groups of corefloods was performed. The corefloods and simulator work indicate that the incremental recovery is more than can be accounted for by oil-viscosity reduction and crude-oil swelling. The improved performance is attributed to more favorable displacement characteristics and the presence of a free gas saturation in the cores.

The paper summarizes the historical background of thepressure-volume-temperature analyses of reservoir fluids, the errors involvedin both the sampling and testing of reservoir fluids, the type of informationrequired of a PVT determination, and the field conditions that limit theapplication of anyone analysis. Particular emphasis is placed on the necessityfor approximating as closely as possible the liberation sequence occurring inthe producing formation, flow string, and surface separators. A combineddifferential and flash or "composite" liberation is suggested as thebest means of approximating this liberation sequence. Historical Background Petroleum reservoir engineering commonly is considered to be one of thenewest fields of petroleum science, yet much work of a theoretical andintuitive nature was done many years before the modern techniques of reservoiranalyses were developed. The period 1910–1924 saw considerable work in the field of reservoirbehavior done by the U. S. Bureau of Mines. This work, although entirelytheoretical, pointed out the importance of gas in the recovery of oil from thereservoir. The statement by J. O. Lewis that 20 per cent or less of theoil originally in place in a pool was recovered from the ground under uncurtailedproduction conditions caused some operators to re-examine and modify theirproduction methods. However, though these works showed methods of productionthat have subsequently resulted in greater oil recoveries, they in general wentunnoticed, even though there was a fear that the nation's petroleum resourceswere being exhausted. The period 1924–1933 saw the industry take considerably more interest inreservoir behavior because of an unfounded fear of its inability to replace oilreserves, the possibility of government regulation, and the energy of one man, Henry L. Doherty. Doherty aroused heated discussions in the industry concerningconservation. To prove or disprove his theories the first experimental work onthe reservoir behavior of petroleum was undertaken. The papers of Dow andCalkin, Beecher and Parkhurst, and Mills and Heithecker are classics althoughtheir experimental procedures were crude. These papers proved that theproperties of petroleum in the reservoir are quite dissimilar to the propertiesmeasured at the well head. Gas dissolved in the oil phase was recognized ashaving considerable importance as had been predicted by the earliertheorists. T.P. 3710

This paper describes the rectifications and extensions made to a Beta-type, three phase, three dimensional, numerical reservoir simulator which make possible the modeling of caustic and/or polymer possible the modeling of caustic and/or polymer displacement of oil. The performance of a caustic laboratory core flood has been matched using this new simulator. The simulation model developed from the core flood matches will be used to predict the performance of the caustic flood to be undertaken in the performance of the caustic flood to be undertaken in the Wilmington Field - Ranger Zone - Fault Block VII. The modified simulator for enhanced waterflooding accounts for the injection and/or production of up to six active agents in the aqueous production of up to six active agents in the aqueous phase. Any or all of these agents may be either phase. Any or all of these agents may be either caustic or polymer-type fluids or a combination of these two fluid types. The primary displacement effects of the caustic fluids are represented by changes in relative permeabilities to oil and water. This simplified permeabilities to oil and water. This simplified approach permits the modeling of enhanced recovery projects without the necessity of determining the projects without the necessity of determining the mechanisms of the displacement in minute detail. For Ranger Zone, Fault Block VII, caustic flood relative permeability curves and caustic consumption parameters for use in the numerical simulator were parameters for use in the numerical simulator were determined from linear displacement studies of conventional waterflooding and saline, caustic waterflooding using Ranger Zone crude oil and core samples. Introduction The Wilmington Field of Southern California is the largest field in California. The field has seven basic reservoir zones with crudes that have a relatively low gravity, high viscosity, and high organic acid content. The recovery efficiency for the waterflood of the Ranger Zone of the Wilmington Field has been low due primarily to a highly unfavorable mobility ratio between water and oil, and significant reservoir stratification. The concept of utilizing natural organic acids present in a crude oil to produce surfactants when present in a crude oil to produce surfactants when the oil is contacted by alkaline water — although limited to reservoirs with higher acid content oils — has potential economic advantages over the use of commercial surfactants owing to the high costs of these chemicals and the low cost of sodium hydroxide. Several mechanisms have been proposed for the improved oil recovery resulting from caustic waterflooding. Included among these mechanisms are (1) emulsification and entrainment, (2) wettability reversal (oil-wet to water-wet), (3) wettability reversal (water-wet to oil-wet) and (4) emulsifilcation and entrapment. The relationships between these possible mechanisms is necessarily more complicated in caustic waterflooding than in surfactant injection due to the complexity of the alkali-organic acid reactions which form soaps in-situ. Siefert has studied the naturally occurring emulsifiers in crude oil and found that the number in a specific crude oil may range into the hundreds. The Department of Oil Properties for the City of Long Beach and THUMS Long Beach Company, in conjunction with the United States Department of Energy, have undertaken a caustic waterflooding demonstration project in the Ranger Zone, Long Beach Unit, project in the Ranger Zone, Long Beach Unit, Wilmington Field to demonstrate the applicability of the caustic injection process to the recovery of that field's crudes. Included in this project is an extensive laboratory core flood analysis program and modeling of the caustic displacement process using a numerical simulator. The development of the numerical simulator and its use in modeling the core flood work performed to date are presented in this paper. CAUSTIC DISPLACEMENT PROCESS Although the possible mechanisms and chemical reactions in caustic flooding are very numerous and complex all the major mechanisms postulated are characterized by immiscible displacement of oil by aqueous solutions at greatly reduced interfacial tensions.