Alkaline Surfactant Polymer (ASP) flooding is a chemical EOR method to increase oil recovery after water flooding through IFT reduction and increasing sweep efficiency. Previous studies have shown that maximal oil recovery is reached when ASP flooding is performed at optimum salinity conditions, i.e. Winsor type III micro-emulsion phase but a recently series of core-flood experiments indicated that comparable oil recovery could be obtained at under-optimum salinity conditions (Battistutta et al. 2015). Mechanistic simulation of ASP flooding considering phase behavior of water-oil-surfactant system, geochemical reactions and alkaline consumption is needed to validate the experimental data and provide a robust model for field scale studies. In this paper detailed history matching of series of core-flood experiments was attempted. Experiments were performed at different salinity conditions (optimum vs. under-optimum) and with different core types (Bentheimer and Berea) using a single olefin sulfonate (IOS) and crude oil with very low acid number (<0.05 mg KOH/g oil). The numerical simulations were performed using UTCHEM, multiphase multi-component simulator along with EQBATCH module to model the geochemical reactions. Neglecting the effect of in-situ surfactant (soap) generation, since the acid number of crude oil was low, modeling of the phase behavior showed an excellent match against experimental data and optimal salinity was observed at 2.0 wt% NaCl (+ 2.0 wt% Na₂CO₃).Using this and considering aqueous and cation exchange as the most important geochemical reactions in alkaline propagation, several ASP core-flood experiments at optimum vs. under-optimum salinity conditions were successfully modeled. An excellent matching of all the measured parameters including oil cut and recovery, pressure drop, pH and carbonate, alkali and surfactant concentration at effluent was also achieved. Modeling confirms the results obtained from experiment which regardless of core type, although minimum achieved IFT at optimum salinity conditions is lower than the one achieved at under-optimum conditions, comparable final oil recovery was observed for both cases. This emphasizes the importance of performing ASP flooding at under-optimum salinity conditions due to lower surfactant retention and reducing the likelihood of achieving over-optimum salinity conditions. In this paper a robust model which is calibrated with experimental data is presented to simulate ASP flood process at various conditions and the basic model can be used to perform further simulations and can provide practical and convenient approach to model field applications of ASP flooding.

Alkaline−surfactant−polymer (ASP) flooding is potentially the most efficient chemical EOR method. It yields extremely high incremental recovery factors in excess of 95% of the residual oil for water flooding on the laboratory scale. However, current opinion is that such extremely high recoveries can be achieved under optimum salinity conditions, i.e., for the Winsor Type III microemulsion phase characterized by ultralow interfacial tension (IFT). This represents a serious limitation since several factors, including alkali-rock interaction, the initial state of the reservoir water, and the salinity of injected water, may shift the ASP flooding design to either sub-optimum or over-optimum conditions. A recent experimental study of ASP floods, based on a single internal olefin sulfonate (IOS) in natural sandstone cores with varying salinity from sub-optimum to optimum conditions, indicated that high recovery factors can also be obtained under sub-optimum salinity conditions. In this paper, a mechanistic model was developed to explore the causes behind the observed phenomena. The numerical simulations were carried out using the UTCHEM research simulator (at The University of Texas at Austin), together with the geochemical module EQBATCH. UTCHEM combines multiphase multicomponent simulation with robust phase behavior modeling. An excellent match of the numerical simulations with the experiments was obtained for oil cut, cumulative oil recovery, pH profile, surfactant, and carbonate concentration in the effluents. The simulations gave additional insight into the propagation of alkali consumption, salinity, surfactant profiles within the core. The study showed that the initial condition of the core is important in designing an ASP flooding. Because of uncertainties in the various chemical reactions taking place in the formation, an accurate geochemical model is essential for operating an ASP flooding in a particular salinity region. The simulation results demonstrate also that, for crude oil with a very low total acid number (TAN), the ultralow IFT and low surfactant adsorption can be achieved over a wide range of salinities that are less than optimal. The results provide a basis to perform better modeling of the suboptimum salinity series of experiments and optimizing the design of ASP flooding methods for the field scale with morecomplicated geochemical conditions.