An Improved Reservoir Understanding of the Impact of Initial Oil Composition and Residual Oil Saturation on Brine Composition and Calcite Scaling During CO2 – WAG EOR in Carbonate Reservoirs

Abstract

Abstract This paper provides an improved understanding of the impact of initial oil composition and residual oil saturation on brine composition and calcite scaling during CO2 Water-Alternating-Gas (WAG) Enhanced Oil Recovery (EOR) in carbonate reservoirs. It assesses the impact of different initial oil compositions and residual oil saturations in the reservoir using reactive transport modelling. Geochemical parameters, such as concentrations of CO2, Ca2+, HCO3- and pH are analysed as the propagating injection fronts reach the producer block. The study uses a 1D model of WAG injection in a carbonate core, assuming a light oil and desulphated seawater injection into calcite as the rock substrate. The isothermal reactive transport modelling is performed using a compositional reservoir simulator coupled to a geochemical model that uses the WOLERY database. Formation water and injected water compositions are based on published data for Brazilian pre-salt fields. Henry's Law is used to calculate CO2 partitioning, particularly from residual oil into injected brine. Typically, solubility of CO2 will be greater in the injection than in the formation brines. The results show that the higher the residual oil saturation, the longer that the injected brine becomes saturated with CO2 before the CO2 is depleted from the oleic phase. Hence, calcite dissolution due to acidification of the injection brine continues for longer, the higher the residual oil saturation. Therefore, calcium and bicarbonate concentrations remain high for longer in the produced brine after injection water breakthrough, increasing the scaling risk. The scale risk becomes even greater in reservoirs with an initial oil composition rich in CO2. This is because there is more CO2 dissolved in the oil phase which will partition into the brine during the water injection cycle. As a result, the waterfront becomes more reactive for longer and hence dissolves more calcite, thus leading to a higher level of calcite scaling in the production system. The conclusion is that CO2 partitioning from the oleic to the injected aqueous phase has a greater impact on in situ calcite dissolution and reprecipitation in the producer wells than does CO2 partitioning from the injected gas directly into the aqueous phase. This work demonstrates, for the first time, how the residual oil saturation and initial oil composition impact geochemical reactivity in carbonate reservoirs, affecting the extent of in situ fluid-rock interactions. It demonstrates that the higher the CO2 concentration in the initial oil and the higher the residual oil saturation, the greater the calcite scaling risk in production wells during water breakthrough, with the residual oil facilitating mass transfer into injected brine.