Advanced waterflooding is a process in which the ionic strength as well as the ionic composition of the injected water is tuned to improve the oil recovery. It has been observed in field trials and in lab coreflooding experiments; advanced waterflooding has the potential to recover additional oil. This process has been evaluated as a wettability-modifying agent in carbonates and captured the global research focus in water-based enhanced oil recovery (EOR) methods. This paper provides a comprehensive review of the published research to speed the process of further investigations in this field. The review provides the most current information to the reader about advanced waterflooding and a guide to the relevant papers for those who are new in this field.
The accurate determination of the wetting condition of carbonate reservoirs is a prerequisite for the selection of any enhanced oil recovery (EOR) fluid. Most carbonate formations are initially oil-wet to intermediate-wet at reservoir conditions. In order to correctly chose an EOR fluid to alter the wettability, we need to understand the initial wetting conditions and design an ionically modified water (advanced water) to alter wettability and improve oil recovery. If a reservoir has already been reached to the optimum wetting conditions by injecting formation water or any other fluid, then there is no need for ionically modified water. A number of methods have been devised to identify the wetting conditions including contact angle measurements, spontaneous imbibition, and chromatographic separation, etc. But contact angle measurement requires surfaces that lack natural surface roughness, spontaneous imbibition tests take months, and chromatographic separation is feasible only for core flooding in sulfate free carbonates at low temperature. A novel application of the well-established technique known as flotation was used in this study to measure the oil-wet and water-wet percent of pure biogenic chalk (Dan Chalk from Denmark). It is an accurate, fast, and most reliable method to quantitatively measure the water-wet and oil-wet fractions of a reservoir rock. It determines the potential of advanced water to improve wettability within days, instead of measurements that can take months and require expensive equipment. Using this technique we were able to quantify the wettability alteration caused by low salinity and potential determining anions (PDAs) such as SO4 2–, BO3 3–, and PO4 3–. The wettability data show maximum oil recovery by dilution is coincident with maximum wettability alteration. The experiments also show that the presence of sulfate or borate enhances wettability alteration by dilution. Moreover, the combined and individual effect of potential scale forming ions (Ba2+ and Sr2+) on wettability restoration was identified. The effect of interfacial tension (IFT) on the measured wettability alteration and the amount of oil attached to the water-wet percent of rock was also determined.
Adjustment of the ionic composition and strength of injected or imbibed brine for enhanced oil recovery (EOR) in carbonate reservoirs has been an area of active research for the past two decades. Despite many successful laboratory and field applications, the method has been reported ineffective in other cases. Most of the published results attributed EOR to improved water wetness in initially oil-wet carbonates. Nevertheless, in a few studies, EOR was observed without apparent wettability alteration. We undertake the analysis of a large set of published recovery experiments to try to identify the critical mechanisms at the pore scale. Better pore scale physicochemical understanding will guide the formulation of accurate reservoir-scale models. This paper presents a comprehensive meta-analysis of the proposed mechanisms using multivariate data analysis. Detailed review of the subject, including mechanisms with supporting and contradictory evidence, has been presented by Sohal et al. In this study, the significance of each contributing factor to EOR was quantified and subjected to rigorous multivariate statistical analysis. The analysis was limited because there is no uniform methodology or sampling protocol. We confined our analyses to experiments with sufficient data so as many potential contributing factors as possible could be evaluated. We were able to identify the most important factors that control increased recovery in chalk and limestone experiments. We also found the most critical measurements to provide the best basis for interpretation of the experiments that guide future recovery experiments and provide better results.
The additional oil recovery from fractured and oil-wet carbonates by ionically modified water is principally based on changing wettability and often attributed to an improvement in water-wetness. The influence of different parameters, such as dilution of salinity, potential anions, temperature, pressure, lithology, pH, and oil acid and base numbers, to improve waterwetting has been tested in recovery experiments. In those studies, the temperature is mainly investigated to observe the reactivity of potential anions (sulfate and borate) at different concentrations. However, the influence of systematically increasing the temperature on wetting conditions has not been thoroughly investigated. In this experimental study, the effect of different temperatures on wettability for brines of different ionic strength and composition has been investigated in depth. A series of flotation experiments was conducted at 23, 50, and 100 °C using Dan outcrop chalk. The effect of each individual variable on the wetting condition was tested independently. The brines included seawater, seawater without sulfate, seawater (augmented with 2−4 times sulfate), and seawater containing borate instead of sulfate. All brines were diluted 2, 4, 10, 20, and 100 times. It was observed that, as the temperature increased, the water-wetness decreased for seawater and seawater dilutions; however, the presence of elevated sulfate can somewhat counter this trend because sulfate increased oil-wetting.
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