Quantification of solubility trapping in natural and engineered CO2 reservoirs

Secure retention of CO2 in geological reservoirs is essential for effective storage. Solubility trapping, the dissolution of CO2 into formation water, is a major sink on geological timescales in natural CO2 reservoirs. Observations during CO2 injection, combined with models of CO2 reservoirs, indicate the immediate onset of solubility trapping. There is uncertainty regarding the evolution of dissolution rates between the observable engineered timescale of years and decades, to the >10 kyr state represented by natural CO2 reservoirs. A small number of studies have constrained dissolution rates within natural analogues. The studies show that solubility trapping is the principal storage mechanism after structural trapping, removing 10–50% of CO2 across whole reservoirs. Natural analogues, engineered reservoirs and model studies produce a wide range of estimates on the fraction of CO2 dissolved and the dissolution rate. Analogue and engineered reservoirs do not show the high fractions of dissolved CO2 seen in several models. Evidence from natural analogues supports a model of most dissolution occurring during emplacement and migration, before the establishment of a stable gas-water contact. A rapid decline in CO2 dissolution rate over time suggests that analogue reservoirs are in dissolution equilibrium for most of the CO2 residence time.Supplementary material:https://doi.org/10.6084/m9.figshare.c.5476199Thematic collection: This article is part of the Geoscience for CO2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage

A Numerical Analysis of the Effects of Supercritical CO2 Injection on CO2 Storage Capacities of Geological Formations

One of the most promising means of reducing carbon content in the atmosphere, which is aimed at tackling the threats of global warming, is injecting carbon dioxide (CO2) into deep saline aquifers (DSAs). Keeping this in mind, this research aims to investigate the effects of various injection schemes/scenarios and aquifer characteristics with a particular view to enhance the current understanding of the key permanent sequestration mechanisms, namely, residual and solubility trapping of CO2. The paper also aims to study the influence of different injection scenarios and flow conditions on the CO2 storage capacity and efficiency of DSAs. Furthermore, a specific term of the permanent capacity and efficiency factor of CO2 immobilization in sedimentary formations is introduced to help facilitate the above analysis. Analyses for the effects of various injection schemes/scenarios and aquifer characteristics on enhancing the key permanent sequestration mechanisms is examined through a series of numerical simulations employed on 3D homogeneous and heterogeneous aquifers based on the geological settings for Sleipner Vest Field, which is located in the Norwegian part of the North Sea. The simulation results highlight the effects of heterogeneity, permeability isotropy, injection orientation and methodology, and domain-grid refinement on the capillary pressure–saturation relationships and the amounts of integrated CO2 throughout the timeline of the simulation via different trapping mechanisms (solubility, residual and structural) and accordingly affect the efficiency of CO2 sequestration. The results have shown that heterogeneity increases the residual trapping of CO2, while homogeneous formations promote more CO2 dissolution because fluid flows faster in homogeneous porous media, inducing more contact with fresh brine, leading to higher dissolution rates of CO2 compared to those in heterogeneous porous medium, which limits fluid seepage. Cyclic injection has been shown to have more influence on heterogenous domains as it increases the capillary pressure, which forces more CO2 into smaller-sized pores to be trapped and exposed to dissolution in the brine at later stages of storage. Storage efficiency increases proportionally with the vertical-to-horizontal permeability ratio of geological formations because higher ratios facilitate the further extent of the gas plume and increases the solubility trapping of the integrated gas. The developed methodology and the presented results are expected to play key roles in providing further insights for assessing the feasibility of various geological formations for CO2 storage.

Effect of Temperature on the Geological Sequestration of CO2 in a Layered Carbonate Formation

Geological sequestration of carbon dioxide (CO2) in deep saline aquifers is one of the most promising technologies for large-scale CO2 mitigation. Temperature can play a significant role in the ensuing geochemistry, affecting equilibria in a multicomponent system and impacting reactive transport processes. The objectives of this study are to quantify the effect of temperature on storage efficiency, solubility trapping of CO2, pH of residual brine, and changes in the mineralogy and porosity. Using toughreact 3.3 (a reactive transport simulator), we have simulated the injection of CO2 into a heterogeneous layered carbonate formation for a period of 50 years, followed by a 50-year equilibration period with no injection. Mineralogy and physical properties of the simulated aquifer are based on a dolomitic limestone aquifer located within the South Florida Basin. Simulations were conducted for seven values of temperature. Density of supercritical CO2 decreases with an increase in temperature, which leads to higher buoyancy at elevated temperatures. Therefore, the storage efficiency of the aquifer decreases as temperature increases. Simulation results indicate that an increase in temperature from 35 °C to 95 °C results in a 35% decrease in storage efficiency. However, surprisingly, solubility trapping of CO2 increases with an increase in temperature because the interfacial area increases with temperature. Temperature effects on pH and on porosity change (due to mineral dissolution and precipitation) are small. The study can be helpful in screening a reservoir for geological carbon storage based on the formation temperature.