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The conditions necessary for optimum low tension and phase behavior at high surfactant concentrations are compared with those required at low surfactant concentrations, where solubilization effects are not usually visible. Major differences in tension behavior between the high and low concentration systems may be observed when the surfactant used contains a broad spectrum of molecular species, or if a higher molecular weight alcohol is present, but not otherwise in the systems studied. We compared the effects of a number of aliphatic alcohols on tension with phase behavior. An explanation of these results, and also of other observed parameter dependences, is proposed in terms of changes in surfactant chemical potential. Surfactant partitioning data is presented that supports this concept. Introduction Taber and Melrose and Brandner established that tertiary oil recovery by an immiscible flooding process should be possible at low capillary process should be possible at low capillary numbers. In practice, the required capillary number, which is a measure of the ratio of viscous to capillary forces governing displacement of trapped oil, may be achieved by lowering the oil/water interfacial tension to about 10(-3) dyne/cm, or less. Subsequent research has identified a number of surfactants that give tensions of this order with crude oils and hydrocarbon equivalents. Interfacial tension studies tended to fall into two groups. Work at low surfactant concentrations, typically 0.7 to 2 g/L, has established that a crude oil may be assigned an equivalent alkane carbon number. Using pure alkanes instead of crude oil has helped the study of system parameters affecting low tension behavior. Important parameters examined include surfactant molecular structure, and electrolyte concentration, surfactant concentration, surfactant molecular weight, and temperature. At higher surfactant concentrations, interfacial tension has been linked to the phase behavior of equilibrated systems. When an aqueous phase containing surfactant (typically 30 g/L), electrolyte, and low molecular weight alcohol is equilibrated with a hydrocarbon, the surfactant may partition largely into the oil phase, into the aqueous phase, or it may be included in a third (middle) phase containing both water and hydrocarbon. Low interfacial tensions occur when the solubilization of the surfactant-free phase (or phases) into the surfactant-containing phase is maximized. Maximum solubilization and minimum tensions have been shown to be associated with the formation of a middle phase. Both the high and low surfactant concentration studies have practical importance because even though a chemical flood starts at high concentration, degradation of the injected surfactant slug will move the system toward lower concentrations. This study investigates the relationship between tension minima found with low concentration systems, and low tensions found with equivalent systems at higher surfactants concentrations, particularly those in which third-phase formation occurs. Many of the systems studied here contain a low molecular weight alcohol, as do most surfactant systems described in the literature or proposed for actual oil recovery. Alcohol originally was added to surfactant systems to help surfactant solubility, but can affect tensions obtained with alkanes, and with refined oil. Few systematic studies of the influence of alcohol on tension behavior exist. Puerto and Gale noted that increasing the alcohol Puerto and Gale noted that increasing the alcohol molecular weight decreases the optimum salinity for maximum solubilization and lowest tensions. The same conclusions were reached by Hsieh and Shah, who also noted that branched alcohols had higher optimum salinities than straight-chain alcohols of the same molecular weight. Jones and Dreher reported equivalent solubilization results with various straight- and branched-chain alcohols. In this study, we fix the salinity of each system and instead vary the molecule; weight of the hydrocarbon phase. SPEJ P. 242

The interfacial tension of surfactant mixtures with hydrocarbons obeys a simple scaling rule. Many apparently inert surfactants give low tensions when in mixtures; the scaling rule still applies to these mixtures. The influence of surfactant structure and molecular weight on low-tension behavior zs examined, and the application of these results to the optimization of surfactant flooding systems is discussed.

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The Low Tension Polymer Flood approach addresses the two EOR problems of cost and control. Coinjection of low concentration surfactant and a biopolymer, followed by a further mobility control buffer, leads to much reduced overall chemical consumption, even in relatively high clay content rock. Though the optimum chemical injection period is more prolonged, the oil recovery timescale is not unduly prolonged. The LTPF process moves chemical flooding surfactant a long way toward being a simple, low-level waterflood additive process, attractive for field operations. It uses surfactant-polymer interactions as an advantage rather than coping with them as a problem. The chemical system described is based on a scleroglucan biopolymer (500 – 750 ppm) plus surfactant mixture (3000 ppm total surfactant). No cosolvent is used. This system was developed specifically for use with high salinity injection water (seawater) in a high temperature reservoir. The essential phase behavior description is given, together with other physical parameters and detailed core flood performance. Finally, we discuss the computer simulation approach used to predict reservoir performance and the results obtained. predict reservoir performance and the results obtained Introduction Many surfactant-polymer field tests have been conducted over the past three decades. This activity stemmed from the promise of highly effective oil recovery by surfactants in a period of increasing oil prices. Results of these tests and critical reviews published on them prices. Results of these tests and critical reviews published on them identified the main parameters important to the technical success of a surfactant-polymer project. One of the key findings is that preflushes to remove excessive salinity and hardness have been preflushes to remove excessive salinity and hardness have been ineffective and chemical systems capable of being effective in the presence of both injection brine and formation water are presence of both injection brine and formation water are needed. A second important conclusion is that effective and timely oil recovery from surfactant-polymer field tests correlates well with maintaining good mobility control of both the surfactant slug and the polymer buffer. Further, as the pattern size increases so does the polymer buffer. Further, as the pattern size increases so does the need for having a salinity tolerant system with favorable mobility control. However, this is not meant to suggest that other design parameters such as low interfacial tension and high injectivity are unimportant. Rather, we should focus on robustness and control as also being mandatory. In this context, waterflood modification with viscous polymer alone is usually reported as being technically and economically successful in field operations addressing mobility control problems. However the process effectiveness is generally low. It successful, oil recoveries are process effectiveness is generally low. It successful, oil recoveries are in the range of 2-12% of the residual oils. Since the oil price fall of 1986, concerns over the risks, costs, ineffectiveness and test failures considered to be associated with chemical flooding have led to widespread abandonment of chemical EOR research by the scientific community. In addressing these concerns we decided to explore ways of combining the effectiveness of surfactants with the control of polymers. The properties of the combined system, which we refer to as Low Tension Polymer Flood (LTPF), can confer some significant advantages. The aim of LTPF is to increase the oil recovery of a relatively ineffective but low chemical cost polymer flood by the addition of limited amounts of polymer compatible surfactants. The basic LTPF injection scheme described here involves the injection of up to 0.7 swept pore volume (PV) of LTPF with additives comprising about 3000 ppm surfactant(s) and 500–750 ppm polymer in a brine. This is ppm surfactant(s) and 500–750 ppm polymer in a brine. This is followed by 0.5 PV of graded viscosity polymer buffer. However, optimum flood design, including presence or absence of a polymer preflood and length/level of chemical additions, depend on reservoir description. If operationally attainable, the salinity of the make-up water used for the polymer buffer may be made lower than that used during LTPF injection to take advantage of the salinity gradient effect. Thus LTPF is technically a bridge between the surfactant and polymer flooding processes. processes. P. 475