Characterization of Formation Water for Feasibility Analysis of Injection Water for Enhancing Crude Oil Recovery in a part of the Sandstone Porous media of the upper Assam Basin
The characterization of in-situ formation water in oil reservoirs plays a critical role in the evaluation of the reservoir rock characteristics. The pH of the produced formation water that flows along with oil and gas infers the current wetting properties of the reservoir rock. The porous media belonging to part of the Tipam and Barail formations of the upper Assam basin are mostly water-wet sandstone rocks that often result in high water cut issues. This produced water, after collecting at surface installation and subsequent treatment in the effluent treatment plant, meets the criteria for injection into the sub-surface formations to maintain reservoir pressure and the flowability in oil wells that lack sub-surface pressure to push well fluids into the wells. Low salinity water flooding is a preferred method of oil production to increase oil recovery from aged oil fields. In the current work, formation water from the upper Assam basin was modified to smart water with the addition of divalent salt ions to examine its performance with monovalent salt ions. This paper characterises nine (9) wellhead water samples from parts of the oilfields of Tipam and Barail formations in the upper Assam basin. The evaluation includes the analysis of pH, conductivity, turbidity, total dissolved solids (TDS), dissolved oxygen (DO), oil and grease (O & G), salinity (Sal), and determination of inorganics by flame photometer. The findings of the current study reveal that smart water can enhance crude oil recovery in the upper Assam basin compared to low salinity water, as the interaction of this water with rock and crude oil results in alteration of the rock's wetting conditions.