TX 75063-3636, U. S.A.,fax 01-972-952-9435. AbstractThis experimental investigation studied the use of additives to enhance foam properties and improve the in-situ generation of foams for improving gas flooding sweep efficiency. Some of the parameters affecting foam performance were polymer concentration, different surfactants and their concentration, aqueous phase salinity and pH, and effect of ffow rate (or shear rate).Performance of polymer enhanced foams (PEF) was much better when compared to conventional foams. Polyacrylamide polymers were used as an additive. Higher foam resistance and longer foam persistence were achieved by using relatively low concentrations of polymers. The studies also showed that the foam performance was significantly improved over a broad range of polymer concentrations.A number of other investigators have shown that foams are severely affected in the presence of oil. This is especially true of lighter or less viscous oils, and the destabilizing effect is magnified with a higher salinity aqueous phase. PEF with a low salinity aqueous phase showed improvement in foam stability. The effective viscosities of PEF were higher than those of conventional foams with a high salinity aqueous phase and the presence of lighter oils. Further, PEF reduced the negative impact of oils on foam mobility. Of the surfactants studied, alpha olefin sulfonates were tolerant to high salinity brines as well as being compatible with polymer additives. Other surfactants, including amine oxide surfactants, were also studied and showed unusually high foam resistance and stability. Introduction..__ ---_.. Because of recent advances in technology, C02 flooding has become a readily available improved oil recovery method. Significant amounts of residual oil can be recovered by carbon dioxide (COJ flooding. Studies' have shown increasing trends for C02 flood projects in the United States, as well as in other countries. However, many, if not all, gas flooding field projects are often hampered by early C02 breakthrough, poor sweep efficiency, and inefficient oil recovery due to viscous fingering resulted from a low gas phase visco-sity and an unfavorable mobility ratio.Poor sweep efficiency may also be caused by stratification or fracturing. Reservoir heterogeneity, particularly layering, is one of the most important factors that affects C02 flood performance. C02 mobility is usually high relative to that of other reservoir fluids, and the resulting unfavorable mobility ratio enhances fingering that initially results from reservoir heterogeneity or gravity override. In more heterogeneous reservoirs, the C02 floods some layers more easily because of differences in porosity and permeability. In this case, the C02 breaks through faster to the producing wells. More C02 is then required over the lifetime of the ffood, which leads to higher C02 costs per barrel of oil recovered and greater handling and recycle expenses.A need to control gas phase mobility has resulted in many studies of processes which may alleviate the adve...
The applicationof carbon dioxideor other gases to extract crude oil from depleted reservoirs has been shown to be a technically successful proceeds. However, optimized recoveries are often compromisedby poor sweep efticienciesbecause of low gas viscositiesand densities. A new process was investigatedthat potentiallycould improvesweep efficienciesby enhancing extractabilityproperties of the injected gas with entrainers. Use of a capillary viscometer to evaluate enhanced viscosities appeared to be the best procedure for evaluatingcandidatecompounds. A mathematicaltreatmentwas proposed based on predictingentrainersolubilities and minimummiscibilitypressurealterationsfor carbon dioxide. However, use of many assumptions and approximations limited the effectiveness of this approach to qualitative evaluations. Some 87 compoundswere evaluated using this mathematical treatment, and certain monoaromaticcompoundswere identifiedfor further laboratorytesting.
Summary. The control of fluid mobility has become increasingly important to steamflood applications for oil recovery. Most of the EOR projects in the U.S. use steamflooding techniques. The efficiency of these projects is often reduced because such effects as gravity override result in poor volumetric sweep through the reservoir. Additives can improve the efficiency of steamflooding, but screening tests must be performed for selection oil the most effective additive for individual applications. As potential additives, nine commercially available sulfonate surfactants were tested with the high-temperature/high-pressure foamability (HTHPF) test procedure. and eight (if these were tested with the mobility control (MC) procedure. These surfactants were evaluated at 250 and 425deg.F [121 and 218deg.C] in deionized water and in 1% added NaCl. A correlation trend was also found between foam stability measured by the HTHPF test and mobility reduction measured by the MC test. This trend was evident for more than one type of sulfonate at both temperatures an increase in temperature corresponded to a decrease in foam stability and mobility reduction. The dependence of- foam stability on the presence of added NaCl varied from surfactant to surfactant. Introduction Steamflooding is the most commercially successful F-OR method in use. About 80% of the oil currently produced by EOR in the U.S. is reported to be from steamflooding. The volumetric sweep efficiency of steam, however, is often lowered by such phenomena as gravity separation, viscous fingering. and reservoir heterogeneity. The literature contains considerable information about ways of improving volumetric sweep efficiency. One method that may prove to be effective is the use of foams generated in situ. Foams are used to reduce the mobility of steam in highly permeable, steam-swept zones created through gravity override. If the mobility of the steam can be reduced in those areas, migration of the steam zone to other less easily accessible regions in the reservoir will be improved. The properties of foams have been studied extensively. Previous investigations have included studies of foam quality, foam viscosity, foam flow patterns, surface tension, wetting ability, foam stability, foam morphology, foam rheology, and permeability-reduction proper-ties. Foam stability and permeability-reduction properties were studied in this research. To select and to test surfactants for steamflood applications, surfactants that can be foamed at high temperatures and high pressure must be identified. Some suitable surfactants have been identified by use of a high-pressure cell located inside an air bath. In that research, static and dynamic foam stabilities were determined. Half-life times were calculated on the basis of first-order kinetics. A similar test, used in our laboratory to identify potential foaming surfactants, is called the HTHPF test. Several investigations of foam mobilities in Porous media have also been reported. Although different procedures were used in each study, these procedures can be classified as two basic types: continuous injection of foaming surfactant (steady state) and slug injection of foaming surfactant (nonsteady state,). Studies that use the first type are cited in 6 through 9. and studies that use the second type in Refs. 10 through 15. The test used in this study is the second type and similar to that used by Sharnia et al, where the unconsolidated matrix is presaturated with surfactant solution. This test is referred to as the MC test. Today, engineers must base their selection of a surfactant for optimum use in a steamflood field operation on a surfactant for optory tests designed to characterize all the properties of foaming surfactants. Little work has been done, however, to compare the results of the differently types of laboratory test with results of steam-flood applications for the same additives. In this paper. the results of the HTHPF test are compared with the results of the MC test for a given set of additives. This comparison represents the first step toward evaluating the effectiveness of laboratory screening tests. Experimental Equipment. Fig. 1 is a schematic of the HTHPF apparatus. The injection of N, is controlled with metering valves and pressure regulators to maintaining constant gas flow for foam generation. The N, passes through sintered stainless-steel spargers (7-um pore size) to generate the foam inside the pressure cells. The pressure cells are 500 mL in volume with 20-in. [51-cmi -long glass windows in front and back. The cells are rated to 700 psi 14.8 MPa] at 400deg.F [204deg.C). The N, is preheated before it enters the cells as it passes through tubing coils inside the oven. Fig. 2 is a schematic of the MC test apparatus. The core holder has an ID of 1.7 in. [4.4 cm] and is 36 in. [91 cm] long. Differential pressure across the entire core is measured throughout current experiments by a Validyne pressure transducer with a demodulator and strip-chart recorder. Surfactant Solutions. The solutions were prepared by dissolving, the surfactant as received from the suppliers into deionized water or 1 % NaCl solution to obtain a 1 wt% surfactant solution. Surfactant solutions with and without added NaCl were tested by the HTHPF procedure, and surfactant solutions without added NaCl were tested by the MC procedure. A variety of commercially available surfactants for steamflood applications were tested. The types tested and described in this report include alpha-olefin sulfonates (AOS's), alkyl-aryl sulfonates (AAS's), and ethoxy sulfonates (EOS's). All the surfactants were tested as received from the commercial suppliers. The concentration of active ingredients in weight percent is given in Table 1. Operating Procedures. HTHPF Test. The test operating, conditions were set at 650 psi 14.5 MPa] and -50 or 425deg.F [121 or 218deg.C]. The oven was allowed to equilibrate for 60 minutes after it reached the desired temperature. N2 was added through the sparger to generate a foam column. The height of this column was 4.7 in. [12 cm], except for measurements reported in Table 2 where the foam heights are specified. SPERE P. 543^
Understanding the effect of the components of commercial olefin sulfonates on steam foam performance would aid manufacturing more cost-effective products. Commercial alkene sulfonates are a mixture of alkene sulfonate, hydroxyalkane sulfonate, and olefin disulfonate. The effect of these components, hydrophobe linearity, the position of the carbon-carbon double bond in the substrate (alpha-olefin compared to internal olefin), hydrophobe carbon number, and hydrophobe linearity on foaming properties and other properties of interest for enhanced oil recovery was studied. The connectivity index measure of chemical structures correlation with 121 C (250 F) foam stability provided a correlation coefficient of 0.98. Introduction Improved engineering concepts such as horizontal injection and production wells are improving oil recovery economics in steam enhanced oil recovery projects. The use of alpha-olefin sulfonates and other surfactants as steam foaming agents has been studied extensively at many laboratories. These studies include both laboratory tests and field pilots. The general consensus is that steam mobility control surfactants providing improved cost effectiveness are needed. The objective of this report is to describe structure property relationships of olefin sulfonates that aid in predicting their steam mobility control performance and identifying improved candidates with a minimum of laboratory screening studies. The results of original experiments are reported. In addition, previously published results are reconsidered from a surfactant structure - property perspective. Steam foam sand pack floods which serve as a basis for discussing the effect of hydrophobe carbon number and branching are described in references 3 and 4. Experiments of similar design have been described elsewhere. The connectivity index was originally developed to relate physical and biological properties of organic compounds to one or more connectivity indices, mXb. (m is the order of the connectivity index and b is the type.) The physical significance of the connectivity index is somewhat unclear but appears to depend on the topology of the molecule and therefore could be directly related to many physical properties. The connectivity index, I, is calculated using Equation 1: (1) wherein: I is the connectivity index d1 and d2 are the valence electrons (excluding those bonded to hydrogen atoms Appendix A provides a simple example, the calculation of the connectivity index of 1-butanol. The methodology used to calculate the connectivity index values for olefin sulfonates is also summarized. The first order connectivity index used herein tends to reflect the relative molecular surface area of the molecule and accounts for branching. Larger molecules have higher connectivity indices since they contain more atoms and bonds. As branching increases for a given number of carbon atoms, the connectivity index decreases indicating a more compact molecule. P. 91^
Thie -r wss prepared for pre.santstion at the SPE/COE Ninth Symposium on Improved Oil Recovav held in Tuka, Okklwma, U.S.A., 17-20 April 1994. This p-r wea selected for preaantstion by an SPE Program Commiktaa following review of infc+nration mntsined in en abatraof submhfed by the authc+'(s). Contents of the paper, ss~nt~. hw not bean reviewed by the SmktY of Petroleum Engineers and are subjecf to cwaofion by the suthor(s). The materisl, as presented, dme not na4aasdy retied any poahion of Ihe smiety of Petroleum Engineers, its officers, or members. PsPsm presented at SPE mwi~ws aub@f to~blitimn~iew by Edwial~m~a~the *@Y of Petroleum Engineers. permission to wpy is restrkfad to an sbstmot of not rrmre than XXI wads. Iliuatmtkme may not be copkad. The abatmf ahcsdd oonfain mnapkuowe aoknc+dadgmant of where and by whom the psper is presented, Write Librarian, SPE, P.0, Sox SS3SSS, Rkhardson, TX 7SOSMSSS, U.S.A., Tafax 1SS24S SPEUT.
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