Surfactant Screening Research Articles

Preliminary studies on the development of a microbiological treatment for polychlorinated biphenyls

A series of experiments comprising microbiological testing, surfactant screening and microcosm systems are described for the preliminary development of a treatment for polychlorinated biphenyls (PCBs). Microbial isolates from contaminated soil and sludge and culture collections, were screened for degradation of a defined mixture of PCB congeners in liquid culture. Initially, one group of bacteria substantially degraded the dichloro-to pentachlorobiphenyls except where chlorinated at the 4,4' position, but not hexachlorobiphenyl; whereas other microorganisms, includingPhanerochaete chrysosporium, showed greater degradation of the apparently more recalcitrant congeners. Repeated subculturing of the most promising bacteria on biphenyl supplemented media apparently increased their ability to degrade both the range and extent of congeners tested. The non-ionic Triton(®) X-100 and Tensoxid(®) S50 were the most effective surfactants at desorbing PCB from sand but had varying degrees of inhibition either to the growth, or alternatively to the PCB metabolism of the isolates tested. The greatest degree of PCB metabolism in the presence of Triton(®) X-100 was towards 2,3-dichlorobiphenyl, with a general reduction in the degree of degradation of trichlorinated to hexachlorinated congeners. The most effective reduction of Aroclor(®) 1242 in sand systems spiked with 1,000 mg/kg was achieved through a combination of inoculating biphenyl-degrading bacterial isolates together withPh. chrysosporium. This resulted in a reduction of approximately 40% in a 20-week period, although this was attributable largely to the removal of the less chlorinated rather than the more chlorinated congeners.

Design and Evaluation of a Nitrogen-Foam Field Trial

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⁁

Multiphase Microemulsion Systems

Abstract Economical microemulsion flooding inevitably involves microemulsion phases immiscible with oil or water, or both; oil recovery is largely affected by displacement efficiency during the immiscible regime. Therefore, it is essential to understand the role of interfacial tension in relation to multiphase microemulsion behavior. Three basic types of multiphase systems are identified and used to label phase transitions that occur when changes are made in salinity, temperature, oil composition, surfactant structure, cosolvent, and dissolved solids in the aqueous phase. Directional effects of these changes on phase behavior, interfacial tension, and solubilization parameter are tabulated for the alkyl aryl sufonates studied. A relationship between interfacial tension and phase behavior is established. This provides the phase behavior is established. This provides the basis for a convenient method for preliminary screening of surfactants for oil recovery. Interfacial tensions were found to correlate with the solubilization parameter for the various microemulsion phases, a result that can substantially reduce the number of interfacial tensions that must be determined experimentally for a given application. Introduction A previous paper established that microemulsion flooding is a locally miscible process until slug breakdown and is an immiscible, rate-dependent displacement thereafter; furthermore, for an effective flood, most of the oil recovered is acquired during the immiscible regime. An extensive study of single-phase regions defined classes of micellar structures for a particular surfactant; however, it was subsequently shown these did not affect oil recovery, provided viscous, lamellar structures were avoided. Optimal salinity was introduced as defining a ternary diagram having the least extensive multiphase region, a desirable feature in that locally miscible displacement is prolonged. Immiscible displacement after slug breakdown is known to depend on interfacial tension through its inclusion in the capillary number. A brief study showed chat interfacial tension varied widely throughout the multiphase region; accordingly, it is anticipated that oil recovery will depend on details of multiphase behavior in relation to interfacial tension, as well as on injection composition. Consider a flood sufficiently advanced that the microemulsion slug has broken down. A microemulsion phase remains that is immiscible with water or oil, phase remains that is immiscible with water or oil, or both, and displacement has assumed an immiscible character. The problem is twofold: to design a microemulsion slug that effectively displaces oil at the front and that is effectively displaced by water at the back. Both aspects are essential and, therefore, both microemulsion-oil and microemulsion-water interfacial tensions must be very low. The condition where these two tensions are low and equal will be of particular significance. The purpose of this paper is to explore physicochemical properties of multiphase physicochemical properties of multiphase microemulsion systems with a view toward understanding immiscible aspects of microemulsion flooding, and with the expectation of developing systematic screening procedures useful for design of optimal floods. Equilibration is an essential part of this study. Even the simplest of these systems is so complex it may well happen that nonequilibrium effects will never be understood sufficiently to be usefully accommodated in mathematical simulation of microemulsion flooding. In any event, equilibration, although time consuming, leads to a coherent picture of multiphase behavior that can be correlated with flooding results. Multiphase behavior of "simple" ternary systems divides into three basic classes. Dependence of phase behavior on salinity, with respect to these phase behavior on salinity, with respect to these classes, leads to correlations of interfacial tension with the solubilization parameter. These correlations are studied in relation to surfactant structure, temperature, cosolvents, oil composition, and brine composition. Optimal salinity again plays an important role, especially in relation to interfacial tension. SPEJ P. 147

Aqueous Surfactant Systems For Oil Recovery

A slug containing 2 percent sulfonate, polymer for mobility control, and sodium tripolyphosphate for multivalent ion control - the entire system driven by a polymer solution - recovered 85 percent of the residual oil from a waterflooded Berea core. Because the surfactant adsorption is low, it appears that the process may be economically feasible for tertiary recovery of oil. Introduction In 1927, Uren and Fahmy concluded that an inverse relationship exists between oil-water interfacial tension and the percentage of oil recovered by waterflooding. In that same year a patent was issued to Atkinson that proposed the patent was issued to Atkinson that proposed the use of aqueous solutions of soap or other materials to decrease the "surface tension" between oil and the flooding medium and thereby increase the recovery of oil. During the next 25 years a major part of the reported research on the use of surfactants to recover oil was carried out by a group at Pennsylvania State U. This group recognized that interfacial tension. wetting conditions (contact angle), and surfactant adsorption were important factors. Preston and Calhoun discussed chromatographic transport of surfactants through porous rocks. Ojeda et al., and Paez et al., correlated residual oil saturation in Paez et al., correlated residual oil saturation in cores after a surfactant flood with sigma/Delta p and with a pore geometry parameter (k phi)1/2. These correlations pore geometry parameter (k phi)1/2. These correlations indicated that residual oil saturation could go to zero at values of sigma/Delta p approaching zero. Excluding patent literature, published research results for the last two decades have discussed the screening of surfactants for oil recovery "efficiency", changing wettability to improve oil recovery, adsorption and chromatographic transport of surfactants, and the role of major factors known to affect oil recovery by aqueous surfactant flooding. A comprehensive study directed primarily toward the influence of interfacial tension was reported by Reisberg and Doscher in 1956. Using a system that combined an aqueous alkali with a surfactant, they measured interfacial tensions less than 0.01 dynes/cm. With this same chemical system they recovered 100 percent of the oil from sand packs and more than 90 percent from Torpedo sandstone cores. Wagner and Leach showed that oil recovery increases when interfacial tension is reduced to about 0.07 dynes/cm and that further small decreases in interfacial tension result in large increases in oil recovery. In 1968, Taber presented theoretical and experimental results that presented theoretical and experimental results that further clarify the relation between residual oil saturation and Delta p/L sigma. He recognized that this correlation group should include the contact angle, but because of difficulties in systematically varying or indeed in even measuring the contact angle inside rocks, he examined the effects of the other parameters only. For Berea cores Taber found that a significant quantity of discontinuous oil (residual) was displaced when the ratio of Delta p/L sigma reached a value of about 5 (psi/ft)/(dynes/cm). He designated this as the critical value of the ratio and noted that further increases in the value of this ratio invariably produce more residual oil. He concluded that nearly 100 percent of the residual oil can be displaced if very high values of Delta p/L sigma, can be obtained. Gogarty and Tosch have recently discussed the principles of micellar surfactant systems. principles of micellar surfactant systems. JPT P. 186