Experimental and Numerical Modeling of Direct Injection of CO2 Into Carbonate Formations

Abstract

Abstract Sequestration of carbon dioxide in geological formations is an alternative way to manage the carbon emitted by combustion of fossil fuels. Results of an experimental and numerical modeling study aiming to investigate the important aspects of injection of CO2 in carbonate formations are presented. Different from sandstones, in carbonates surface reaction rates are very high, so mass transfer often limits the overall reaction rate, leading to highly non-uniform dissolution patterns. Often, large flow channels called wormholes are created. A distinctive feature of carbonate reservoirs is the porosity/permeability mismatch. Experiments were conducted to investigate the effect of CO2 injection rate, formation temperature, and brine salinity on chemical kinetics and thus permeability and porosity alteration trends through injection of gaseous CO2 into carbonate formations. Experiments were designed to model fast near well bore flow (in horizontal direction) and slow reservoir flows (in vertical direction). It was observed that small changes in porosity may lead to dramatic changes in permeability (presence of preferential flow paths, worm holes). Results of CT-monitored experiments were then used to calibrate a geochemical numerical model where a multi-phase, non-isothermal commercial simulator in which dissolution and deposition of calcite were considered by means of chemical reactions was used. It was observed that solubility and hydrodynamic storage of CO2 was larger compared to mineral trapping. Chemical kinetics leads to dissolution of carbonate and later precipitation of bicarbonate particles. Numerical models together with experimental results proposed that time required for chemical reactions among formation fluid (brine), rock (carbonate) and CO2 was small, that change in effective permeability and absolute porosity were observed within small periods of time. The calibrated model was then used to analyze field scale injections and to model the CO2 sequestration capacity of a hypothetical carbonate aquifer formation. Introduction Carbon dioxide sequestration can be defined as the capture and secure storage of carbon that would be otherwise be emitted to or remain in the atmosphere.1,2 This approach aims to keep carbon emissions produced by human activities from reaching the atmosphere by capturing and diverting them to secure storage. CO2 is sequestrated in geological formations by three mechanisms: solubility trapping through dissolution in the formation water3, mineral trapping through geochemical reactions with the aquifer fluids4,5 and rocks, and hydrodynamic trapping of CO2 plume.3 These mechanisms lead to storage of CO2 as free-phase gas in pore spaces, dissolved phase CO2 in formation water and CO2 converted to rock matrix. Deep saline aquifers in sedimentary basins are possible sites for sequestration of CO2 emitted by combustion of fossil fuels. Brine formations are the most common fluid reservoirs in the subsurface, and more importantly large-volume formations are available practically anywhere. Flow systems that involve water, CO2, and dissolved solids have been extensively studied in geothermal reservoir engineering. The geothermal work mostly addresses higher temperatures and lower CO2 partial pressures than would be encountered in aquifer disposal of CO2; some of it involves not only multiphase flow but also chemical interactions between reservoir fluids and rocks.6 Injection of CO2 into aquifers includes variety of strongly coupled physical and chemical process as multiphase flow, dissolution-deposition kinetics, solute transport, hydrodynamic instabilities due to displacement of less viscous brine with more viscous CO2 (viscous fingering), capillary effects and upward movement of CO2 due to gravity (gravity override).3 Reactions among the formation rock, the aquifer fluid and CO2 may lead to change in the formation permeability and the effective porosity, thus the storage capacity of the formation.