Wettability Modification of Fractured Carbonates Using Sodium Metaborate,Part I: Laboratory Results and Simulation Procedure

Abstract

Chemical-based wettability modification has become important for the worldwide abundance of fractured carbonates with the potential to enhance water imbibition to expel more oil from matrix to the fractures. The authors present systematic experimental and modeling approach on the combined benefit of wettability alteration for enhanced water imbibition and interfacial tension reduction. Brine, alkali, and alkali surfactant solutions were injected sequentially to improve oil recovery from a fractured mix-wet carbonate core. The experiments were successfully modeled with a simulator capable of modeling wettability alteration. Part I presents the experimental procedure and the results. The history match of the waterflood is also presented. In another article the authors describe the procedure to model alkali and alkali surfactant floods including sensitivity simulations of some key parameters.     

The Impact of Surfactants on Wettability Change and Level of Water Imbibition in Relation to EOR in Carbonate Reservoirs

Some anionic, cationic, and nonionic surfactants have been examined on actual reservoir samples. Thin section analysis and core flooding techniques were used for the petrophysical and mineralogical assessments of the rock samples. Spontaneous imbibition experiments were conducted using oil-saturated plugs in combination with reservoir brine and surfactant solutions separately. Capillary pressure measurements were conducted both before and after wettability alteration. Amott-Harvey and USBM wettability indices were determined. Brooks-Corey and Brooks-Corey-Mualem models were used. Among the surfactants a cationic one could best improve the spontaneous imbibition. Fairly good fit was observed between experimental capillary pressure curves and those calculated by Brooks-Corey model.     

The Evaluation of the Impact of Wettability Alteration and Oil Relative Permeability Changes With Temperature During Cyclic Steam Injection in Naturally Fractured Reservoirs Using Horizontal Wells

In this communication, first, cyclic steam injection process in an Iranian heavy oil reservoir was simulated using three horizontal wells and the effect of various operational parameters on the performance was studied. This study has been done on the fractured reservoirs, as there are few studies on cyclic steam injection and the effect of temperature changes on the oil relative permeability in such reservoirs. Then, some practical values of irreducible water saturation and residual oil saturation at different temperatures have been considered for study of their effects on the oil recovery and oil relative permeability, because these practical values are so useful for prediction of production performance. The conclusions indicate that irreducible water saturation and residual oil saturation have significant impact on recovery factor and cumulative steam oil ratio. Comparison of four various methods show the difference in calculated oil relative permeability at various water saturations.     

A Rheological Study of Polymer Using Precipitation Inhibitor,Alkali, and Surfactant for High Salinity in Carbonate Reservoirs

In the present study, a new chemical formulation is designed by combining acrylic acid with the conventional alkali-surfactant-polymer (ASP) components. Acrylic acid generates precipitation inhibitor that dissolves insoluble salts. The salts known as precipitations are formed by the reaction of added chemicals with carbonate reservoir minerals or brine compositions. Various fluid-fluid compatibility tests were first performed to find an optimum acid-alkali ratio to keep ASP solutions without any precipitations for 30 days at 80°C. Using the optimum ratio, a comprehensive study was conducted to investigate the impact of acid, acid-alkali, and acid-alkali-surfactant on the viscosity of copolymer. The optimum acid-alkali ratio was found 0.6:1.0. It was observed that blend of acid with ASP solutions did not cause significant impact on the polymer viscosity. This new chemical combination provided sufficient viscosity for mobility control in the hard brine environment. Hence, the main feature of this work is the development of acid-ASP formulation, which can be more feasible for enhanced oil recovery in carbonate reservoirs as compared to conventional ASP.