Ammonia is logistically preferred over sodium carbonate for alkaline/surfactant/polymer (ASP) enhanced-oil-recovery projects because of its low molar mass and the possibility for it to be delivered as a liquid. On an offshore platform, space and weight savings can be the determining factor in deciding whether an ASP project is feasible. Logistics may also be critical in determining the economic feasibility of projects in remote locations.Ammonia as alkali together with a surfactant blend of alkyl propoxy sulfate/internal olefin sulfonate (APS/IOS) functions as an effective alkali. Surfactant adsorption is low, and oil recovery in corefloods is high. Static adsorption tests show that low surfactant adsorption is attained at pH >9, a condition that ammonia satisfies at low solution concentration.It is expected that ammonia has a performance deficiency relative to sodium carbonate in that it does not precipitate calcium from solution. Calcium accumulation in the ammonia ASP solution will occur, caused by ion exchange from clays. The high oil recovery for ammonia and the calcium accumulation in ASP and surfactant/polymer corefloods with APS/IOS blends show that this surfactant system is effective and calcium-tolerant. Also, phase behavior and interfacial-tension (IFT) measurements suggest that APS/IOS blends remain effective in the presence of calcium. Ethylene oxide/propylene oxide sulfates (such as the used APS) are known commercially available, calcium-tolerant surfactants. However, because of hydrolysis, sulfate-type surfactants are suitable for use only in lower-temperature reservoirs.Very different behavior was noticed for phase-behavior measurements with calcium-intolerant surfactants such as alkyl benzene sulfonates and IOS. In this case, calcium addition results in a very high IFT and complete separation of oil and brine. Presumably, this will result in low oil recovery. A preferred approach for ASP offshore with divalent-ion-intolerant surfactants may be the use of a hybrid alkali system combining the attributes of sodium carbonate and ammonia. The concept is to supply the bulk of the alkalinity for an ASP flood by ammonia with all the inherent logistical advantages. A minor quantity of sodium carbonate is added to the formulation to specifically precipitate calcium ions.

Three carbon dioxide (CO 2 ) foam flooding parameters are addressed in this paper: optimum gas fractional flow, surfactant adsorption behavior, and oil recovery versus CO 2 /aqueous phase injection methodologies. Experimental test conditions were selected to simulate some of the reservoirs in west Texas (1540 psig and 110°F). All tests in this study were conducted in fired Berea sandstone cores to minimize core property changes during a series of CO 2 foam flooding tests. CO 2 and aqueous phase were co-injected during the test. The CO 2 foam flow behavior in the absence and presence of oil and the optimum oil recovery methodologies associated with different stages are described in this paper.This study demonstrates that, with similar residual oil in the core, CO 2 foam had higher oil recovery than CO 2 -brine coinjection. Additional oil was recovered with CO 2 foam injection following CO 2 -brine co-injection. However, no additional oil was recovered if CO 2 foam injection was applied first. The surfactant adsorption equilibrium was characterized by the occurrence of foam.

Phase behavior experiments have identified several surfactant systems that develop high solubilization ratios and low interfacial tension with a specific dead paraffinic crude oil at specific salinities. The purpose of this work is to test these surfactant systems with reconstituted live crude. Emulsion screening tests were performed in sight cells where an equilibrium amount of solution gas is dissolved in the crude at reservoir pressure (1100 psi). The results indicate that the surfactant is relatively more soluble in the oil phase under these conditions. Thus a formulated chemical slug for field conditions should contain either less salinity or a more hydrophilic surfactant system than that used in formulations with dead crude. Phase behavior measurements estimate this offset to be approximately 0.25% less NaCl for the particular live crude in this study. The relevance of this offset is shown by comparing the results of dead crude core floods with a live crude core flood. A control experiment pressurizing oil with nitrogen at the same condition, 1100 psi did not show enhanced relative surfactant solubility in the oil phase.

Phase-behavior experiments have identified several surfactant systems that develop high solubilization ratios and low interfacial tension (IFT) with a specific dead paraffinic crude oil at specific salinities. The purpose of this work is to test these surfactant systems with reconstituted live crude. Emulsion-screening tests were performed in sight cells where an equilibrium amount of solution gas is dissolved in the crude at reservoir pressure (1,100 psi). The results indicate that the surfactant is relatively more soluble in the oil phase under these conditions. Thus, a formulated chemical slug for field conditions should contain either less salinity or a more hydrophilic surfactant system than that used in formulations with dead crude. Phase-behavior measurements estimate this offset to be approximately 0.25% less NaCl for the particular live crude in this study. The relevance of this offset is shown by comparing the results of dead-crude corefloods with a live-crude coreflood. A control experiment pressurizing oil with nitrogen at the same condition, 1,100 psi, did not show enhanced relative surfactant solubility in the oil phase.

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