Safety-based Injection Strategy for Carbon Dioxide Geological Sequestration in a Deep Saline Aquifer with Complex Sandstone-shale Sequences: A Case Study from Taiwan

AbstractThe purpose of this study was to decide the best injection strategy for CO2 geo-sequestration in a deep saline aquifer with complex bedded sandstone-shale sequences. The best injection strategy is decided based on the estimates of the safety index (SFI). Numerical simulation method was used in this study. The major conclusions from this study are: (1) Safe trapping mechanisms contribute to a lower risk of CO2 leakage by trapping CO2 as immobile blobs or changing the phase of CO2 from supercritical phase to aqueous, ionic, and mineral phases in the post-injection period. (2) For an aquifer with complex sandstone-shale sequences, the best injection strategy should be decided by the results of risk evaluation and the SFI estimation. (3) The well location affected the injection strategy. The risk of CO2 leakage was lower using a down-dip injection well than an up-dip well. (4) The best strategy for this case study was to use the down-dip well to inject CO2 into the bottom sandstone layer. The SFI for this scenario reached 0.99 at the storage time of 1000 years, which meant that the probability of CO2 leakage occurring was nearly zero

Case study on safety index for CO2 sequestration in a deep saline aquifer

This study evaluates the risk for CO2 leakage from a storage site using a risk assessment criterion, the safety index, which considers the contributions of residual gas, solubility, ionic, and mineral trapping mechanisms. We present a case of CO2 storage in a deep saline aquifer in Yutengping (YTP) sandstone, Tiehchanshan (TCS) field, Taiwan. The numerical method was used to estimate the amount of different CO2 phases sequestered by the various trapping mechanisms. The CO2 injection rate was 1 million tons per year for 20 years. The total simulation time was 1000 years. In the case of down-dip well injection, the safety index was 0.77 at the storage time of 1000 years and much higher than the safety index of 0.45 for the up-dip well. More mobile supercritical CO2 had to be sealed using a caprock in the up-dip well injection case. Injecting CO2 using a down-dip well is a better engineering strategy because the safety index is higher

Prevention of Seabed Subsidence of Class-1 Gas Hydrate Deposits via CO2-EGR: A Numerical Study with Coupled Geomechanics-Hydrate Reaction-Multiphase Fluid Flow Model

The geomechanics effects and seabed subsidence are critical issues that should be considered in the development of a hydrate reservoir. The purpose of this study is to couple the geomechanics, hydrate reaction, and multiphase fluid flow modules to investigate the feasibility of CO2 enhanced gas recovery (CO2-EGR) of a Class-1 hydrate deposit by observing the formation deformation, and the seabed subsidence. The production methods of depressurization and CO2-EGR are modeled, respectively. The production behaviors and seabed subsidence of different production methods are compared. The positive influence on the gas recovery for a Class-1 hydrate deposit via CO2-EGR is observed. The calculations of seabed subsidence showed a significant improvement can be achieved when CO2-EGR was used. The subsidence is only 6.8% of that from the pure depressurization in the case of a pressure drop of 30%. The effects of production pressure drop and production gas rate are investigated. The association between the gas production and the pressure drop of the well is different from the cases of pure depressurization and the CO2-EGR. The appropriate initial time for the CO2 injection is tested. Slighter seabed subsidence is observed when the CO2 injection is initiated earlier. The case of different injection pressure control showed that a lower injection pressure leads to a heavier seabed subsidence. A higher CO2 fraction allowed in the produced gas stream results in a higher cumulative gas production, but there is no significant impact on the seabed subsidence

Plume Migration of Different Carbon Dioxide Phases During Geological Storage in Deep Saline Aquifers

This study estimates the plume migration of mobile supercritical phase (flowing), aqueous phase (dissolved), and ionic phase CO2 (bicarbonate), and evaluates the spatial distribution of immobile supercritical phase (residual) and mineral phase CO2 (carbonates) when CO2 was sequestered. This utilized a simulation, in an anticline structure of a deep saline aquifer in the Tiechenshan (TCS) field, Taiwan. All of the trapping mechanisms and different CO2 phases were studied using the fully coupled geochemical equation-of-state GEM compositional simulator. The mobile supercritical phase CO2 moved upward and then accumulated in the up-dip of the structure because of buoyancy. A large amount of immobile supercritical phase CO2 was formed at the rear of the moving plume where the imbibition process prevailed. Both the aqueous and ionic phase CO2 finally accumulated in the down-dip of the structure because of convection. The plume volume of aqueous phase CO2 was larger than that of the supercritical phase CO2, because the convection process increased vertical sweep efficiency. The up-dip of the structure was not the major location for mineralization, which is different from mobile supercritical phase CO2 accumulation