Understanding the Impact of Water Injection Rate on Brine Composition and Calcite Scaling in Reactive Carbonate Reservoirs as a Function of Oil Composition and Saturation

Abstract

Abstract This paper uses reactive transport modelling to correlate the impact of water injection flow rate on brine composition in carbonate reservoirs with the CO2 concentration in the initial reservoir oil composition and the oil saturation. Brine composition and calcite dissolution near the producer well are evaluated during water flooding. Sensitivity analyses are performed by testing different water injection rates, different CO2 fractions in the initial oleic phase, different residual oil saturations and different distances between the system inlet and outlet. Geochemical properties, such as Ca2+ and HCO3- molalities and calcite dissolution, are analysed at the propagating waterfront. The study is carried out using a 1D model in a carbonate core, assuming light oil, desulphated seawater injection and calcite as the rock substrate. The reactive transport modelling is performed using a commercial compositional reservoir simulator with the WOLERY database. Pressure, temperature, formation water (FW) and injected water (IW) compositions are based on published data. The simulations start with a period of no injection nor production to ensure equilibrium. Henry's Law is used to calculate CO2 partitioning, particularly from residual oil into injected brine. The results show that changes in the water injection rate may have a lesser or a greater impact on geochemical reactions and brine composition, depending on the CO2 concentration in the initial oleic phase and the residual oil saturation. A higher residual oil saturation means a more extended period of CO2 partitioning from the oil phase into the brine during the water flooding, and the waterfront becomes reactive and more saturated for longer due to the higher calcite dissolution, requiring a longer residence time to achieve a full equilibrium in the fluid-rock interaction. In short residence time scenarios, the brine during the non-equilibrium stage becomes more saturated in ions for longer, extending the scale risk after water breakthrough. A different behaviour is observed for scenarios with a higher CO2 concentration in the original oil. The study demonstrates that mineral reactions are less likely to be significantly affected by changes in the water injection flow rate when there is a higher concentration of CO2 in the initial oil phase, and a shorter residence time is required to achieve a full equilibrium. In this scenario, a higher initial CO2 concentration may increase the reaction rate. Thus, the Damköhler number is more likely to be large, and the dissolution of minerals tends to be reaction rate-controlled and less dependent on volumetric throughput. It was also demonstrated that in scenarios where the water injection flow rate affects oil saturation locally, the time that brine takes to react and reach a steady state is also affected. A lower water injection flow rate results in a less effective oil sweep, keeping the oil saturation higher for longer. A higher oil saturation means a more extended period of CO2 partitioning from the oil to the water phase. Thus, the waterfront becomes reactive for longer and more concentrated in Ca2+ and HCO3- ions. A higher oil saturation entails lower water saturation, delaying the water breakthrough and saturating the injected brine with CO2 more quickly, especially when there is plenty of CO2 available in the system. A lower water injection flow rate also allows the fluid-rock interactions to become more fully developed due to the longer residence time. Thus, more calcite dissolves, keeping the brine more highly saturated. The conclusion is that when the distance between the injector and producer is not long enough to allow the fluid-rock interactions to reach equilibrium, the water injection front becomes more saturated in Ca2+ and HCO3- ions for longer as the water injection flow rate decreases and the residual saturation increases, extending the scale risk after water breakthrough. Additionally, as the residual oil saturation grows, brine needs a longer residence time flowing through the reservoir to become insensitive to changes in water injection flow rate. In scenarios with a high CO2 concentration in the initial oil composition, brine is more saturated in Ca2+ and HCO3- ions due to a higher calcite dissolution. Nevertheless, as there is a large amount of the limiting reagent CO2, the system is reaction rate-controlled, and changes in the water injection flow rate have a minor impact on geochemical reactions. This work demonstrates the previously unreported finding that changes in the water injection flow rate may affect geochemical reactions and brine composition as a function of the residual oil saturation and the CO2 availability in the system, eventually making brine more saturated during the non-equilibrium stage and increasing the scale risk by the time of water breakthrough.