Potential for Optimization of Reinjected Produced Water Composition to Improve Oil Production and Reduce Water Production

Abstract

Growing concerns about environmentally friendly enhanced oil recovery (EOR) based on injected water modification / optimization are driving efforts to develop sustainable solutions in the offshore oil industry. Water injection is crucial for providing pressure support and improving oil displacement in most oil reservoirs. Traditional enhanced oil recovery (EOR) methods based on water, involving chemical injections that lead to hazardous chemical flowback and produced water, are being reconsidered. Smart water injection is emerging as a sustainable and environmentally friendly EOR flooding technique. This research work explores production optimization within offshore oil extraction systems by leveraging laboratory experiments and simulations. The focus is on enhancing oil recovery rates while effectively managing the substantial volumes of water generated during gas and oil extraction, including both natural reservoir water and injected water. The research delves into how the composition of brine affects the wetting characteristics of discrete minerals and reservoir rock, particularly Bandera Gray Rock (BGR). Using Surface Complexation Modelling (SCM) simulations with the geochemical solver PHREEQ-C, the study estimates mineral wetting preferences by calculating total bond products derived from the mole fractions of oppositely charged mineral and oil surfaces. By optimizing the ionic composition of injection water, smart water injection enhances reservoir wetting, thereby improving displacement efficiency through increased capillary forces. The Total Bond Product analysis reveals the diverse wettability levels of various minerals when exposed to formation water. It shows that calcite and dolomite have a strong inclination towards oil-wet conditions, a result of potent ionic interactions. On the other hand, quartz maintains its water-wet state with only slight surface complexation. Simulation outcomes indicate that the use of low salinity water (LSSTO1) is notably effective in shifting wettability towards more water-wet conditions. This shift is advantageous for maximizing oil recovery, particularly in reservoirs rich in quartz and clay minerals. Waterflooding is the predominant method employed globally to enhance oil recovery. This thesis investigates the potential for increasing oil recovery through the manipulation of produced water composition used for reinjection. Laboratory core flood experiments were carried out on two core plugs from the Bandera Gray outcrop rock. The tests utilized brines with varying salinity, including formation water, produced water, sea water, and low salinity sea water. A comparison of first flooding of core plug #1 and core plug #2, revealed that FW1 at low rates gives better recovery of 40% than SW at low rates which yielded 33% of oil. Similarly, comparing the other brines used during remaining flooding stages for core plug #1 showed that PW at low-rate gives the maximum incremental volume. This is followed by the PW at high-rate, whereas FW1 at high-rate does not contribute to any incremental volume. The objective of increasing the flow rate was to evaluate the capillary end effect which was later confirmed during high-rate PW injection. The total change in Sor (ΔSor) for core plug#1 is 0.053. Comparison of brines used for flooding in core plug # 2, reveals that LSSW at low-rate gives the maximum incremental volume. This is followed by LSSW at high-rate, and SW at high-rate respectively. Capillary end effect was validated during high-rate LSSW injection. The total change in Sor (ΔSor) for core plug#2 is 0.019.