A Mechanistic Model for Wettability Alteration by Chemically Tuned Water Flooding in Carbonate Reservoirs

Abstract

Injection of chemically tuned brines into carbonate reservoirs has been reported to enhance oil recovery by 5% to 30% OOIP in core flooding experiments and field tests. One proposed mechanism for this improved oil recovery (IOR) is wettability alteration of rock from oil wet or mixed-wet to more water wet conditions. Modeling of wettability alteration experiments, however, are challenging due to the complex interactions among ions in the brine and crude oil on the solid surface. In this research, we developed a multiphase multicomponent reactive transport model that explicitly takes into account wettability alteration from these geochemical interactions in carbonate reservoirs. Published experimental data suggests that desorption of acidic oil components from rock surfaces make carbonate rocks more water wet. One widely accepted mechanism is that sulfate (SO42−) replaces the adsorbed carboxylic group from the rock surface while cations (Ca2+, Mg2+) decrease the oil surface potential. In the proposed mechanistic model, we used a reaction network that captures the competitive surface reactions among carboxylic groups, cations, and sulfate. These reactions control the wetting fractions and contact angles, which subsequently determine the capillary pressure, relative permeabilities, and residual oil saturations. The developed model was first tuned with experimental data from the Stevns Klint chalk and then used to predict oil recovery for additional un-tuned experiments under a variety of conditions where IOR increased by as much as 30% OOIP, depending on salinity and oil acidity. The numerical results showed that an increase in sulfate concentration can lead to an IOR of over 40% OOIP, while cations such as Ca2+ have a relatively minor effect on recovery (about 5% OOIP). Other physical parameters, including the total surface area of the rock and the diffusion coefficient, control the rate of recovery, however not the final oil recovery. The simulation results further demonstrate that the optimum brine formulation for chalk are those with relatively abundant SO42− (0.096 mol/kg water), moderate concentrations of cations, and low salinity (total ionic strength less than 0.2 mol/kg water). These findings are consistent with the experimental data reported in the literature. The new model provides a powerful tool to predict the IOR potential of chemically tuned waterflooding in carbonate reservoirs under different scenarios.

Bulk and Surface Aqueous Speciation of Calcite: Implications for Low-Salinity Waterflooding of Carbonate Reservoirs

“…Thereafter, the rock no longer dissolves (or precipitates) and can no longer etch to release oil. The fact that carbonates equilibrate rapidly with brine necessitates a detailed understanding of aqueous-speciation chemistry (Al-Shalabi et al 2014;Alotaibi and Yousef 2015;Qiao et al 2014Qiao et al , 2016.…”

“…In particular, we demonstrate that injected brine almost immediately equilibrates with carbonate rock. Thus, the assessment of aqueous speciation chemistry is paramount to LSW (Al-Shalabi et al 2014;Qiao et al 2014Qiao et al , 2016. Also pertinent to LSW in carbonates are high-salinity brine and lack of clay content, both of which affect the DLE recovery mechanism.…”

Chelating-Agent Enhanced Oil Recovery for Sandstone and Carbonate Reservoirs

“…The f-potential measurements were conducted with the f-potential analyzer (Zetapals).The Zetapals instrument uses a phase-analysis light-scattering technique to determine the electrophoretic mobility (measure of speed) of charged colloidal suspensions, and calculates the f-potential (in mV) with the Smoluchowsky and Huckel models (Sze et al 2003). One can write Smoluchowsky's equation as follows:…”

Compositional Modeling of Dissolution-Induced Injectivity Alteration During CO2 Flooding in Carbonate Reservoirs

“…Water-Alternating Gas (WAG) Injection. WAG is the most commonly used method for CO 2 enhanced oil recovery (Christensen et al 2001;Rogers and Grigg 2001). It is a challenge to simulate WAG when both gas dissolution and water vaporization are considered because of the rapid disappearance and reappearance of the hydrocarbon and aqueous phases.…”

“…Solvent injectivity is generally observed to decrease in field projects even though CO 2 has a lower viscosity than the fluids it is displacing (Henry et al 1981;Winzinger et al 1991). Rogers and Grigg (2001) stated that one possible reason for observed injectivity decreases is the impact of mineral reactions between brine and carbonates. At the Wasson Denver Unit, pre-and post-pilot core studies showed anhydrite dissolution during the water-injection portion of the WAG cycles, although the amount of dissolution was not significant (Mathis and Sears 1984).…”