Pipelining of heavy crudes can be facilitated by preparing oil-in-water (O/W) emulsions of the crude, but separation of the oil from the water after pipelining is problematic if conventional surfactants are used. Long-chain acetamidines are CO 2 -triggered switchable surfactants, being surface-active when CO 2 is present but not when CO 2 is absent. Unfortunately, in the presence of CO 2 , they stabilize water-in-oil (W/O) emulsions of heavy crude rather than the desired O/W emulsions. However, in the absence of added CO 2 , several compounds (Na 2 CO 3 , three of the long-chain acetamidines, and two other amidines) stabilize O/W emulsions. These low-viscosity emulsions can later be broken by the addition of CO 2 . The residual oil content in the recovered water is lowest if the compound used to stabilize the original emulsion was a long-chain acetamidine.

Summary This paper describes the planning, implementation, and evaluation of anN2-foam field trial at the Painter reservoir in Wyoming. Foam properties of aproprietary surfactant were measured in corefloods at reservoir conditions andmodeled with an empirical foam simulator. Foam injection into a dualinjector/producer temporarily reduced injectivity but was ineffective incontrolling N2 channeling. Introduction The laboratory objectives of this project were to determine experimentallythe effectiveness of foam in controlling N2 mobility at reservoir conditionsand to develop a simulator for predicting foam behavior in a reservoir. Theobjectives of the field trial were to determine the handling characteristics ofsurface-generated foam, to provide field data for validating the simulator, andto see whether foam could control N2 channeling at a dual injector/producer. The dual well selected for the field trial had an N2 cut of 50% and was instratigraphic communication with two offset wells where the N2 cuts weregreater than 20%. Laboratory work included surfactant screening, displacementexperiments to characterize foam properties, and development of a foamsimulator. Screening procedures identified a proprietary surfactant as anappropriate foaming agent. The surfactant produced a stable, low-mobility foamin the presence of Painter reservoir fluids. A permeability reduction factormeasured in the displacement experiments was used in the simulator to predictfoam injectivity and transport behavior in the reservoir. For the field trial,20,400 res bbl [3244 res m3] of 60%-quality foam was injected over a 7-weekperiod. N2 was mixed with a brine solution containing 0.5- to 1.5-wt%surfactant before going downhole. The resulting high-density foam reduced N2injectivity by a factor of 10, as predicted by the simulator. N2 injectivityrecovered rapidly after foam injection was completed. Well performance wasessentially unchanged after the foam treatment; there was neither a reductionin N2 cut nor an increase in oil production. More N2 channeling was evident inthe postfoam injection profile, possibly from overpressuring the well. Analysisof postfoam pressure-falloff tests showed that the effects of foam diminishedgradually over several months. The systematic approach taken in this projectcorrelated laboratory and field data with an empirical foam simulator. Thisapproach yielded a better understanding of the foam process, improvedinjectivity predictions, and a more complete evaluation of the field trial. Themethods described in this paper provide the basis for designing future foamtreatments. Background Discovered in 1977, the Painter reservoir is located in the Overthrust Beltof southwestern Wyoming. Hydrocarbon introduction is from the Jurassic Nuggetsandstone, which is approximately 1.000 ft [305 m] thick. The upper two-thirdsof the reservoir is gas condensate, and the lower portion is a light, paraffinic (44 API [0.81-g/cm3]) oil. Table 1 lists average reservoirproperties. We started pressure maintenance by N2, injection in 1980. The plan was toincrease reservoir pressure from 4,200 to 4,700 psig [29 to 32 MPa] so thatcondensate would miscibly displace the oil. N2 was injected in dual-completion(injection/production) wells along the crest of the formation. N2 broke throughmore rapidly than expected in the dual injector/producers and in offsetproducers that are in stratigraphic communication with injection wells. The N2channeling at Painter is attributed to stratigraphic communication betweeninjection and production wells, coning in dual injector/producers, and complexreservoir geology. Gas flows preferentially along the bedding planes ratherthan atop down or perpendicular to the bedding planes, as postulated forefficient miscible displacement. In the dual wells, large pressure gradientscombined with high N2 mobility cause gas coning, which shuts off oilproduction. This effect is accelerated if vertical fractures exist or ifproblems with the well completion are experienced. The reservoir geologyconsists of sand dunes that have directional permeability and uncertain arealextent. Permeability also varies with the grain size of the laminae that makeup a dune set. A foam-mobility-control project was initiated to evaluate thefoam's potential for controlling N2 channeling. JPT P. 504⁁

Summary A laboratory study was undertaken to find more efficient, lower-cost chemical systems for the recovery of waterflood residual oil. Our investigation emphasized alkaline-augmented processes because alkali is much less expensive than surfactant. The strategy was to replace some of or all the high-cost surfactants in a micellar formulation with lower-cost alkali and still maintain the high tertiary oil recoveries obtained with micellar flooding. Baseline oil recoveries in Berea corefloods were determined for two interfacially active crude oils with micellar/polymer (MP) and alkaline/polymer (AP) systems. A combination process was then developed in which a small micellar slug is injected first, followed by a larger AP slug. This process is referred to as a micellar/alkaline/polymer (MAP) flood. Phase-behavior studies guided the design and optimization of all three chemical processes in the coreflood experiments. Detailed effluent analyses and in-situ mobility measurements provided information about possible oil recovery mechanisms. Well-designed MAP systems recovered more possible oil recovery mechanisms. Well-designed MAP systems recovered more than 80% of the waterflood residual oil, comparable to the best MP systems These recoveries were achieved with only one-third the surfactant and cosurfactant required in the MP system. AP systems recovered less oil than either the MAP or MP systems. The chemical efficiency (ratio of the total chemical cost to oil recovered) of the MAP systems was better than the efficiency of the MP systems and comparable to that of AP systems. Similar results were obtained for both crude oils. Introduction Micellar flooding has received much attention in laboratory studies and field tests in recent years. This process is attractive because the displacement efficiency of an effective micellar flood can be almost 100% in zones swept by surfactant. However, this EOR process has yet to be implemented on a commercial scale because process has yet to be implemented on a commercial scale because of economic considerations. A recent Natl. Petroleum Council study I of EOR in the U.S. projects that the production from chemical flooding with current technology will be only 17% of production from all EOR processes. Micellar flooding alone is not likely production from all EOR processes. Micellar flooding alone is not likely to begin widespread application until the 1990's and will account for only 14% of future EOR. One major impediment to the commercialization of micellar flooding is the high cost of the surfactant and cosurfactant required to mobilize the residual oil in the reservoir. In this paper, our objective is to reduce the amount of surfactant needed for an effective chemical flood. Specifically, we investigated the use of inexpensive alkaline agents as substitutes for the more expensive surfactant chemicals. The results of this study are used to compare the performance and characteristics of the combined surfactant/alkaline performance and characteristics of the combined surfactant/alkaline process with that of surfactant and alkali alone. Others have reported a beneficial synergistic effect from combining surfactant and alkali in a chemical flood. When properly designed, adding surfactant to the alkaline slug can increase oil recovery significantly in laboratory corefloods. With polymer included for mobility control, the oil recovery can be as high as that obtained with a conventional micellar flood. Some authors suggest that the proper combination of these chemicals lowers interfacial tension (IFT) and reduces surfactant adsorption. Other possible benefits from alkali include a favorable change in wettability possible benefits from alkali include a favorable change in wettability and enhanced mobility control from the creation of emulsions. Two California crude-oil/brine systems (denoted A and B) were selected for this laboratory study. Initial work identified an MP system that displaced Oil A well in laboratory coreflood tests. Similar experiments with Oil B and an AP system showed that this process effectively displaced this higher-acid-number crude oil. The next stage of our investigation focused on combining alkali and surfactant to improve the oil recovery and chemical efficiency for both candidate reservoirs. The objective for Reservoir A was to maintain the high recovery obtained for the existing MP design, but with a significant decrease in the amount of expensive surfactant and cosurfactant. The objective for Reservoir B was to improve significantly upon the oil recovery for alkaline or AP floods by adding a minimal amount of surfactant. As a result, an improved MAP process was designed for both reservoirs.

Commercial samples (75-250 µ thick) of polyacrylate and cellulose triacetate polymers were found to be selectively permeable to S02. Ultrathin films (0.05-10 µ thick) of these polymers were prepared to achieve the high S02 fluxes which are required for S02 gas separations. The results of tests with pure N2, C02, and S02 showed that N2 and C02 permeabilities were nearly independent of pressure but the S02 permeability had a large pressure dependence which adversely affected membrane performance. S02 permeation data were correlated with twoand three-parameter exponential models. The effects of membrane thickness, additives, and time on permeability were also investigated.

Summary. This paper presents a case history where laboratory and simulation results were used to model a single-well polymer injectivity field test in the West Coyote field and to improve injectivity in a sub-sequent field test. The polyacrylamide used in the first tesxhibited low injectivity. Laboratory studies were performed to identify the causes of low injectivity and to model the field test physically. Laboratory core data and reservoir properties were used in a mathematical model to calculate the polymer injectivity, which closely matched that observed in the field. The low polymer injectivity at West Coyote was a result of formation damage caused by the polymer and low-salinity polymer makeup water and the high resistance factor developed by the polymer. These problems were overcome by using a lower-molecular-weight polyacrylamide, preshearing the polymer solution before injection, and increasing the salinity of the polymer makeup water. These improvements resulted in a 50% polymer makeup water. These improvements resulted in a 50% increase in injectivity during the second polymer injectivity field test at West Coyote. Introduction Two single-well evaluation programs for the micellar/polymer process were conducted in the Main and 99 West pools at the West Coyote field. The objectives were to determine oil saturations before and after micellar displacement tests, to characterize the field handling and injectivity of micellar/polymer fluids, and to obtain additional geologic data for an improved reservoir model. This paper focuses on the polymer injectivity tests performed at these field trials. An earlier paper discussed performed at these field trials. An earlier paper discussed the overall program for the first field trial at Well MC-374. The micellar formulation tested at Well MC-374 was effective in reducing the waterflood residual oil saturation from 0.32 to 0. 10, but the polymer injection rate was only 70% of the design rate. Both oil displacement efficiency, and in injectivity are key factors in determining the economics of a chemical flood. The injectivity for the first program at West Coyote was too low to generate an program at West Coyote was too low to generate an acceptable rate of return for a commercial-size project. In subsequent laboratory work, the causes of low injectivity were identified, and a new chemical system was designed and tested at Well MC-375. This paper first describes the field operations and polymer injectivity data for Well MC-374. On the basis of polymer injectivity data for Well MC-374. On the basis of field operations, several causes for the low injectivity were postulated and later verified in laboratory corefloods that postulated and later verified in laboratory corefloods that physically modeled the field test. A reservoir simulator physically modeled the field test. A reservoir simulator incorporated these laboratory data into a mathematical model of injectivity. Next, alternatives for improving polymer injectivity were evaluated, and an improved polymer injectivity were evaluated, and an improved Polymer system was selected for testing at Well MC-375. Polymer system was selected for testing at Well MC-375. Field and laboratory data were compared through reservoir simulation and pressure transient analysis. The premise of this paper is that the chemical solution mobilities measured in laboratory corefloods can be related to mobilities that exist in a field flood. Such laboratory tests can thus be used to predict and to optimize mobility control and injectivity for the field. This approach was used successfully in the chemical slug mobility design for a micellar flood at the Big Muddy field . It was shown there that the slug mobilities measured in the laboratory closely matched those observed in the field. Well testing can also be used to interpret polymer-injectivity field tests and to calculate the in-situ polymer mobility in the reservoir. West Coyote Field The West Coyote oil field is located at the eastern end of the Los Angeles basin, near La Habra, CA. This field has six oil zones. The Main and Upper 99 zones contain the most oil in place and are the subject of this paper. The Main and Upper 99 are divided into eight subintervals, six in the Main and two in the Upper 99. The field is a candidate for EOR because the current water cuts are in excess of 98% and the waterflood is forecasted to last only into the 1990's. Micellar flooding was selected as a potential EOR process, because West Coyote is a light-oil reservoir with a moderate temperature and low salinity. Reservoir properties are listed in Table 1. Well MC-374 Polymer-injectivity Test A polymer-injectivity test was performed in the top 20 ft [6 m] of the Main zone Sand B in March 1982 (Fig. la), starting a few weeks after a micellar oil displacement test in the same interval. The results of a single-well tracer test indicated that the micellar solution reduced the average oil saturation to 0. 10 in the near-wellbore region (20-ft [6-m] radius). SPERE P. 271