Changhe Qiao

Compositional Modeling of Dissolution-Induced Injectivity Alteration During CO 2 Flooding in Carbonate Reservoirs

Geochemical reactions between fluids and carbonate rocks can change porosity and permeability during carbon dioxide (CO2) 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 CO2 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 CO2 and water injected. For continuous CO2 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 CO2 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 CO2-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 seawater lead to similar injectivity increases. Carbonated waterflooding (a special case of SWAG) shows even greater porosity increases than SWAG because more water is injected in this case, which continuously sweeps out calcite-saturated brine. The minerals have a larger solubility in brine than in fresh water because of the formation of aqueous complexes, leading to more dissolution instead of precipitation. Overall, this research points to the importance of considering the complex process coupling among multiphase flow, transport, phase behavior, and geochemical reactions in understanding and designing schemes for CO2 flooding as well as enhanced oil recovery at large.

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

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 4 ) replaces the adsorbed carboxylic group from the rock surface, whereas cations (Ca2þ, Mg2þ) 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 Ca2þ 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 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.

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

Geochemical reactions between fluids and carbonate rocks can change porosity and permeability during CO2 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 CO2 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 CO2 and water injected. For continuous CO2 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 CO2 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 CO2-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) shows even greater increases in injectivity than SWAG because more water is injected in this case, which can continuously sweep out brine saturated with calcite. The results also show that scaling can occur beyond the zone of dissolution depending on the type of water injected. For seawater injection, injectivity first increases and then decreases owing to formation of gypsum. The amount of precipitation depends on the compatibility of the injected brine with the formation water that is equilibrated with high pressure CO2 and minerals. We consider only gypsum and halite precipitation here, although other types of scale could be easily included. Introduction CO2 flooding is the leading enhanced oil recovery (EOR) method in both sandstone and carbonate reservoirs in the United States (Christensen et al. 2001; Manrique et al. 2007). CO2 can become miscible with the oil and therefore significantly improve the recovery (Jarrell et al. 2002). Recovery can be adversely impacted if injected CO2 channels through high permeability layers and causes early breakthrough of solvent and poor sweep. Water is typically injected along with CO2 to

Analytical decoupling techniques for fully implicit reservoir simulation

This paper examines linear algebraic solvers for a given general purpose compositional simulator. In particular, the decoupling stage of the constraint pressure residual (CPR) preconditioner for linear systems arising from the fully implicit scheme is evaluated. An asymptotic analysis of the convergence behavior is given when t approaches zero. Based on this analysis, we propose an analytical decoupling technique, from which the pressure equation is directly related to an elliptic equation and can be solved efficiently. We show that this method ensures good convergence behavior of the algebraic solvers in a two-stage CPR-type preconditioner. We also propose a semi-analytical decoupling strategy that combines the analytical method and alternate block factorization method. Numerical experiments demonstrate the superior performance of the analytical and semi-analytical decoupling methods compared to existing methods.