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

Abstract

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)...

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