Injection of chemically tuned brines into carbonate reservoirs has been reported to enhance oil recovery by 5-30% original oil in place (OOIP) in coreflooding 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 morewater-wet conditions. Modeling of wettability-alteration experiments, however, is challenging because of the complex interactions among ions in the brine and crude oil on the solid surface. In this research, we developed a multiphase and multicomponent reactive transport model that explicitly takes into account wettability alteration from these geochemical interactions in carbonate reservoirs.Published experimental data suggest that desorption of acidicoil components from rock surfaces make carbonate rocks more water-wet. One widely accepted mechanism is that sulfate (SO 2À 4 ) replaces the adsorbed carboxylic group from the rock surface, whereas cations (Ca 2þ , Mg 2þ ) 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 untuned 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 more than 40% OOIP, whereas cations such as Ca 2þ have a relatively minor effect on recovery (approximately 5% OOIP). Physical parameters, including the total surface area of the rock and the diffusion coefficients, control the rate of recovery, but not the final oil recovery. The simulation results further demonstrate that the optimum brine formulations for chalk are those with relatively abundant SO 2À 4 (0.096 mol/kg water), moderate concentrations of cations, and low salinity (total ionic strength of 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. To the best of our knowledge, this is the first model that explicitly and mechanistically couples multiphase flow and multicomponent surface complexation with wettability alteration and oil recovery for carbonate rocks specifically.

The injection of low-salinity brines can improve oil recovery in carbonate reservoirs by changing the rock wettability from being more oil-wet to being more water-wet. Existing models use an empirical dependence of wettability based on variables including equivalent salinity and ionic strength. We recently developed a process-based model that mechanistically includes the geochemical interactions between crude oil, brine, and the chalk surface that alter rock wettability. In this research, we extend the previous model by including mineral dissolution reactions, therefore enabling the modeling of low-salinity flooding in chalks and limestone cores with and without anhydrite, which is considered to be a key factor in controlling the extent of improved oil recovery (IOR). We examine the role of mineralogy by including surface complexation, aqueous reactions, and dissolution/precipitation of calcite and anhydrite in the extended model. These reactions, coupled with the equations of multiphase flow and transport, are solved simultaneously using an in-house simulator, PennSim. Relative permeability functions and residual oil saturation during flooding are adjusted dynamically according to the concentration of oil acids attached to the mineral surface. Core flooding experiments from the Stevns Klint (SK) chalk and a Middle Eastern carbonate with a small volume fraction of anhydrite are used to tune the reaction network and predict recovery. Simulation results agree with the observed effluent concentrations of SO4 2–, Ca2+, and Mg2+ reported from chromatographic wettability tests and the measured recoveries under differing compositions in chalk and limestone cores. For the SK chalk without anhydrite, lower Na+ and Cl– concentrations under constant SO4 2– conditions leads to IOR by as much as 6% OOIP. Lower salinity alone, however, does not lead to IOR in limestones without anhydrite. Instead, anhydrite dissolution provides a natural source of sulfate and increases oil recovery by 5% when injecting diluted formation water. Simulations of two-dimensional (2D) five-spot patterns using tuned reaction networks demonstrated that IORs from 5% to 20% OOIP can be obtained after two pore volumes are injected. These IORs are greatly dependent on the aqueous chemistry of the injected fluid and sweep. The results highlight the critical importance of understanding the mineralogy and including a mechanistic reaction model in the simulation of low-salinity water floods.

Injection of low salinity brines can improve oil recovery (IOR) in carbonate reservoirs by changing the rock wettability from oil-wet to more water-wet. Existing numerical simulation models for low salinity flooding use empirical relationships that do not properly capture important processes for wettability alteration, such as aqueous species concentrations, oil acidity, and rock mineralogy. In our previous research on modeling spontaneous imbibition with tuned water (SPE170966), we developed a process-based and predictive model that explicitly includes the chemical interactions between crude oil, brine, and the carbonate surface. In this research, we extend the previous model for low salinity water flooding to both chalk and limestone cores. We examine the role of mineralogy in low salinity waterflooding by developing a mechanistic model for wettability that includes surface complexation, aqueous reactions, and dissolution/precipitation of calcite and anhydrite. The reactions coupled with the equations of multiphase flow and transport are solved simultaneously using an IMPEC in-house simulator, PennSim. Relative permeability functions and residual oil saturation during flooding are adjusted dynamically according to the concentration of oil acids attached to the mineral surface. Core flooding experiments from the Stevns Klint (SK) chalk (Fathi et al. 2010), a limestone with small amount of anhydrite (Austad et al. 2012), and a Middle Eastern carbonate with 6% volume fraction anhydrite (Yousef et al. 2011) are used to tune the reaction network and make recovery predictions. Simulation results give remarkable agreement with the effluent concentrations of SO42−, Ca2+ and Mg2+ reported from chromatographic wettability tests and the recoveries for injection of various brines into chalk and limestone cores of differing compositions. For SK chalk without anhydrite, reducing the Na+ and Cl– concentration of seawater, while keeping SO42− (sulfate) leads to improved oil recovery (IOR) by as much as 6% OOIP. The presence of anhydrite, which provides a natural source of sulfate, also significantly increased oil recovery for injection of diluted formation water and seawater. Simulations of 2D five-spot patterns using tuned reaction networks demonstrated that IORs from 5% to 20% OOIP can be obtained at reasonable values of pore volumes injected (2.0 PVI). These IORs depend greatly on the aqueous chemistry of the injected fluid, and sweep. The results highlight the critical importance of understanding the mineralogy and including a mechanistic reaction model in the simulation of low salinity water floods.

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.

Summary Polymer flooding can significantly improve sweep and delay breakthrough of injected water, thereby increasing oil recovery. Polymer viscosity degrades in reservoirs with high-salinity brines, so it is advantageous to inject low-salinity water as a preflush. Low-salinity waterflooding (LSW) can also improve local-displacement efficiency by changing the wettability of the reservoir rock from oil-wet to more water-wet. The mechanism for wettability alteration for LSW in sandstones is not very well-understood; however, experiments and field studies strongly support that cation-exchange (CE) reactions are the key elements in wettability alteration. The complex coupled effects of CE reactions, polymer properties, and multiphase flow and transport have not been explained to date. This paper presents the first analytical solutions for the coupled synergistic behavior of LSW and polymer flooding considering CE reactions, wettability alteration, adsorption, inaccessible pore volume (IPV), and salinity effects on polymer viscosity. A mechanistic approach that includes the CE of Ca2+, Mg2+, and Na+ is used to model the wettability alteration. The aqueous phase viscosity is a function of polymer and salt concentrations. Then, the coupled multiphase-flow and reactive-transport model is decoupled into three simpler subproblems—the first in which CE reactions are solved, the second in which a variable polymer concentration can be added to the reaction path, and the third in which fractional flows can be mapped onto the fixed cation and polymer-concentration paths. The solutions are used to develop a front-tracking algorithm, which can solve the slug-injection problem of low-salinity water as a preflush followed by polymer. The results are verified with experimental data and PennSim (2013), a general-purpose compositional simulator. The analytical solutions show that decoupling allows for estimation of key modeling parameters from experimental data, without considering the chemical reactions. Recovery can be significantly enhanced by a low-salinity preflush before polymer injection. For the cases studied, the improved oil recovery (IOR) for a chemically tuned low-salinity polymer (LSP) flood can be as much as 10% original oil in place (OOIP) greater than with considering polymer alone. The results show the structure of the solutions, and, in particular, the velocity of multiple shocks that develop. These shocks can interact, changing recovery. For example, poor recoveries obtained in corefloods for small-slug sizes of low salinity are explained by the intersection of shocks without considering mixing. The solutions can also be used to benchmark numerical solutions and for experimental design. We demonstrate the potential of LSP flooding as a less-expensive and more-effective way for performing polymer flooding when the reservoir wettability can be altered with chemically tuned low-salinity brine.

Low salinity water (LSW) is reported to improve oil recovery (IOR) significantly in sandstone and carbonate core experiments. Ranges of IOR vary significantly depending on the chemical composition of brine, oil and cores. We previously developed a process-based and predictive model that explicitly includes the chemical interactions between crude oil, brine, and the carbonate surface that alter rock wettability. In this research, we improve the developed model to include explicitly the acid/base interaction and ion-binding interaction of crude oil adsorption. The wettability alteration is quantified by the surface concentrations of adsorbed carboxylic acids, which is a result of aqueous and surface reactions. The total concentrations of aqueous and surface species are varied individually and together over a large range while precipitation constraints are also included. The wettability is for a variety of brine compositions used in experiments. The wettability depends strongly on the concentration of Ca2+, Mg2+ and SO42−, as well as the total salinity. Including the acid/base interaction can explain the wettability alteration trend when Ca2+, Mg2+ and SO42− concentrations are significant. Including the ion-binding through Ca2+ can better explain the wettability alteration trend when diluted formation water or seawater is injected. We can reproduce the wettability alteration trend reported in experiments from different sources by combining the acid/base and ion-binding mechanisms and considering the irreversibility of the carboxylic adsorption reactions.

Geochemical reactions between fluids and carbonate rocks can change porosity and permeability during carbon dioxide (CO 2 ) flooding, which may significantly affect well injectivity, well integrity, and oil recovery. Reactions can cause significant scaling in and around injection and production wells, leading to high operating costs. Dissolution-induced well-integrity issues and seabed subsidence are also reported as a substantial problem at the Ekofisk field. Furthermore, mineral reactions can create fractures and vugs that can cause injection-conformance issues, as observed in experiments and pressure transients in field tests. Although these issues are well-known, there are differing opinions in the literature regarding the overall impacts of geochemical reactions on permeability and injectivity for CO 2 flooding.In this research, we develop a new model that fully couples reactive transport and compositional modeling to understand the interplay between multiphase flow, phase behavior, and geochemical reactions under reservoir and injection conditions relevant in the field. Simulations were carried out with a new in-house compositional simulator on the basis of an implicit-pressure/explicitcomposition and finite-volume formulation that is coupled with a reactive transport solver. The compositional and geochemical models were validated separately with CMG-GEM (CMG 2012) and CrunchFlow (Steefel 2009). Phase-and-chemical equilibrium constraints are solved simultaneously to account for the interaction between phase splits and chemical speciation. The Søreide and Whitson (1992) modified Peng-Robinson equation of state is used to model component concentrations present in the aqueous and hydrocarbon phases. The mineral-dissolution reactions are modeled with kinetic-rate laws that depend on the rock/brine contact area and the brine geochemistry, including pH and water composition. Injectivity changes caused by rock dissolution and formation scaling are investigated for a five-spot pattern by use of several common field-injection conditions.The results show that the type of injection scheme and water used (fresh water, formation water, and seawater) has a significant impact on porosity and permeability changes for the same total volume of CO 2 and water injected. For continuous CO 2 injection, very small porosity changes are observed as a result of evaporation of water near the injection well. For water-alternating-gas (WAG) injection, however, the injectivity increases from near zero to 50%, depending on the CO 2 slug size, number of cycles, and the total amount of injected water. Simultaneous water-alternating-gas injection (SWAG) shows significantly greater injectivity increases than WAG, primarily because of greater exposure time of the carbonate surface to CO 2 -saturated brine coupled with continued displacement of calcite-saturated brine. For SWAG, carbonate dissolution occurs primarily near the injection well, extending to larger distances only when the specific surface area is small. Formation water and seawate...

Geochemical reactions between fluids and carbonate rocks can change porosity and permeability during CO 2 flooding, which may significantly impact well injectivity, well integrity, and oil recovery. Reactions can cause significant scaling in and around injection and production wells leading to high operating costs. Dissolution-induced well integrity issues and seabed subsidence have also been reported as a substantial problem at the Ekofisk field. Furthermore, mineral reactions can create fractures and vugs that can cause injection conformance issues, as has been observed in experiments and pressure transients in field tests. Although these issues are well known, there are differing opinions in the literature regarding the overall impact of geochemical reactions on permeability and injectivity for CO 2 flooding. In this research, we use fully coupled reactive transport and compositional modeling to understand the interplay between multiphase flow, phase behavior, and geochemical reactions under reservoir and injection conditions relevant in the field. Simulations were carried out using a new compositional simulator (PennSim) based on an implicit pressure explicit composition (IMPEC) multiphase finite-volume formulation that is directly coupled with a reactive transport solver. The compositional and geochemical models were validated separately with CMG-GEM and CrunchFlow. Phase and chemical equilibrium constraints are solved simultaneously to account for the interaction between phase splits and chemical speciation. The Søreide and Whitson (1992) modified Peng-Robinson equation-of-state (EOS) is used to model component concentrations present in the aqueous and hydrocarbon phases. The mineral reactions are modeled kinetically and depend on the rock-brine contact area and the brine geochemistry, including pH and water composition. Injectivity changes caused by rock dissolution and formation scaling are investigated for a five-spot pattern using several common field injection boundary conditions. The results show that the type of injection scheme and water used (fresh water, formation water, and seawater) has a significant impact on porosity and permeability changes for the same total volume of CO 2 and water injected. For continuous CO 2 injection, very little porosity changes are observed owing to evaporation of water near the injection well. For wateralternating-gas (WAG) injection, however, the injectivity increases from near zero to 50%, depending on the CO 2 slug size, number of cycles, and the total amount of injected water. Simultaneous water-alternating-gas injection (SWAG) shows significantly greater injectivity increases than WAG, primarily because of greater exposure time of the carbonate surface to CO 2-saturated brine coupled with continued displacement of calcite-saturated brine. For simultaneous water-alternating-gas injection (SWAG), carbonate dissolution primarily occurs very near the injection well, where dissolution occurs out to greater distances. Carbonated water flooding (a special case of SWAG)...