Surfactant/Polymer Flooding: Chemical-Formulation Design and Evaluation for Raudhatain Lower Burgan Reservoir, Kuwait M. T. Al-Murayri, A. A. Hassan, M. B. Abdullah, and A. M. Abdulrahim, Kuwait Oil Company, and C. Marlie ` re, S. Hocine, R. Tabary, and G. P. Suzanne, EOR Alliance Summary Surfactant/polymer (SP) flooding is an enhanced-oil-recovery (EOR) process that can lead to incremental oil recovery through two mechanisms: reducing oil/water interfacial tension (IFT) to decrease residual oil saturation and increasing the viscosity of the displacing fluid to improve overall sweep efficiency. IFT reduction allows better oil recovery by overcoming capillary effects, while the increased viscosity of the displacing fluid allows a more-homogeneous sweep of reservoir oil. Implementing chemical flooding in reservoirs with relatively high temperature and in-situ salinity (>200,000 ppm) is somewhat challenging. This paper describes the extensive laboratory work performed for the light-oil Raudhatain Lower Burgan (RALB) Reservoir (180  F/82  C) in Kuwait. Reservoir fluids were thoroughly characterized to preselect the most-suitable chemicals for the SP process. Reservoir crude oil was analyzed and recombined with gases (C 1 through C 3 ) depending on the reported gas/oil ratio (GOR) to reproduce the oil in place (OIP) at original reservoir conditions in terms of pressure, temperature, and oil composition. A shift of the live-oil equivalent alkane carbon number (EACN) was compared with the dead-oil EACN. Numerous surfactants were screened according to three main criteria: solubility in the envisioned injection brine, ultralow oil/water IFT, and chemical adsorption on reservoir rock. Different brine types were considered, and the use of adsorption inhibitors was also investigated. Furthermore, polymer screening involving temperature-resistant polymers was conducted by means of viscosity, long- term-aging, and adsorption tests. Polymer compatibility with the selected surfactants was also evaluated. The selected SP formulation was further evaluated through a series of coreflood experiments that were mainly dependent on chemical adsorption on reservoir rock and incremental oil recovery. An injection strategy was designed as a result of these experiments. Laboratory results obtained thus far are encouraging and provide a systematic methodology to design SP injection in high- temperature, high-salinity, and light-oil reservoirs that are similar to the RALB reservoir. Additional technoeconomic evaluation is in progress in preparation for field-scale deployment of SP injection at RALB Reservoir. Background on SP Flooding It is critical to ensure that a pilot project is a success operationally while gathering reliable data for a full-field implementation. For this reason, various aspects of project planning, operational considerations, and pilot objectives need to be addressed. This will not be suc- cessful without a properly designed and executed laboratory-test program. Such a laboratory program will minimize result uncertainty and ensure that the proposed pilot meets its objectives. It is well-established that ultralow IFTs are required to mobilize additional oil when a reservoir has been waterflooded. This has been the subject of many articles (Stegemeier 1976; Green and Willhite 1998; Bavie `re 1991). A process dependent on phase-behavior screening has been described for evaluating potential EOR surfactants (Levitt et al. 2006). This approach uses a well-established rela- tionship between low IFT and microemulsion phase behavior. Surfactant-flooding processes become challenging in high-salinity, hard brines and/or at high temperatures. When hard brine is used as surfactant-makeup brine (injection brine), chemical adsorption is high using conventional injection strategies. This makes the overall process performance limited. High temperature (>176  F/80  C) raises thermal-stability issues with subsequent loss of effectiveness (Tabary et al. 2013). Conventional surfactants for EOR, such as alkyl ether sulfates, are also sensitive to hydrolysis (Wu et al. 2011). Surfactant adsorption on rock has been extensively studied during the past decades (Somasundaran and Hanna 1979; Nelson et al. 1984; Paria and Khilar 2004; Zhang and Somasundaran 2006). The effect of several factors on surfactant retention has been highlighted, including mineralogy (Hirasaki and Zhang 2004), clay content (Wang et al. 1993; Hirasaki et al. 2008), oxidation-reduction potential (Wang et al. 1993; Rajapaksha et al. 2014), and brine composition (Figdore 1982; Flaaten et al. 2010; Tabary et al. 2012), to name a few. Overall, adsorption in surfactant flooding is almost always one of the main limitations of surfactant-flooding performance. During the past decades, several strategies have been proposed and successfully tested to mitigate surfactant adsorption and phase trapping. Use of alkali has been shown to significantly decrease anionic-surfactant adsorption on a variety of rock types (Nelson et al. 1984; Bazin et al. 2011). In addition, Hirasaki et al. (1983) proposed the use of a salinity gradient (Flaaten et al. 2008). This injection strategy, however, could be either nonefficient or nonapplicable in an important number of conditions. Tabary et al. (2012) demon- strated that the efficiency of a salinity-gradient design significantly decreases when hard brines are considered. Brine treatment, either softening or desalinization, appears as an efficient strategy (Henthorne et al. 2011), but needs to be carefully evaluated for high- divalent-ion contents because brine softening and/or dilution have significant economic and logistic consequences. Stoll et al. (2011) described the extensive design process followed by Shell Technology Oman, Petroleum Development Oman, and Shell. The different steps are presented starting from a chemical-phase-behavior study in test tubes, coreflood experiments, and calibra- tion by a comprehensive reservoir-simulation model. In this paper, the authors concluded that the identification of suitable formulations is a laborious process often governed, from their point of view, by trial and error. Copyright V C 2018 Society of Petroleum Engineers This paper (SPE 183933) was accepted for presentation at the SPE Middle East Oil & Gas Show and Conference, Manama, Kingdom of Bahrain, 6–9 March 2017, and revised for publication. Original manuscript received for review 23 July 2017. Revised manuscript received for review 16 April 2018. Paper peer approved 10 May 2018. 2018 SPE Reservoir Evaluation & Engineering 1