Solubility Trapping Mechanisms Research Articles

Numerical investigation of CO2-carbonated water-alternating-gas on enhanced oil recovery and geological carbon storage

This study investigates the potential of a novel CO2-carbonated water-alternating-gas (CWAG) injection method for enhanced oil recovery (EOR) and geological carbon storage. The Weyburn fluid data acquired from Canada are used in a compositional reservoir simulation of a CO2-CWAG case study with seven cycles in order to analyze the effects of carbonated water (CW) upon the oil recovery and CO2 storage capacity of a multi-phase CO2/brine/oil system. The study includes an assessment of the CO2 plume propagation and retention via structural, residual, and solubility trapping mechanisms. The numerical results demonstrate that CO2-CWAG yields a 6.7% increase in oil recovery compared to continuous CO2 flooding (from 68.4% to 73.0%) and a 1.4% increase compared to CO2-WAG (from 72.0% to 73.0%). During the CO2-CWAG operation, increasing the molarity of CO2 from 0.0 mol/L to 1.2 mol/L in carbonated water results in a 6.7% increase in the amount of geologically stored CO2 (from 6191 tons to 6608 tons). In brief, CO2-CWAG improves not only oil recovery but also CO2 storage capacity in terms of the three trapping mechanisms, thus making it a promising low-carbon EOR method that could help reduce CO2 emissions in the oil and gas industry.

Carbon Dioxide Sequestration in Low Porosity and Permeability Deep Saline Aquifer: Numerical Simulation Method

Abstract The saline aquifer is the most reliable place where anthropogenic carbon dioxide gas storage has shown a promising future. This paper evaluates and predicts the capacities of different carbon dioxide storage trapping mechanisms in storing carbon dioxide gas in low porosity and permeability deep saline aquifers by using commercial reservoir simulator software i.e., Computer modeling group (CMG). Four carbon dioxide storage trapping modeled and simulated were structural or stratigraphic trapping mechanisms, residual trapping mechanisms, solubility trapping mechanisms, and mineral trapping mechanisms. Carbon dioxide gas was injected into a deep saline aquifer for 15 years, followed by 833 years of post-injection. To reflect the real field reality and have a reasonable approximation of the amount of carbon dioxide which can be stored in an aquifer, this paper included water vaporization effects that occur during carbon dioxide injection and water injection operations so as to optimize residual and solubility trapping mechanisms as the most important trapping mechanisms. Furthermore, the effects of different important parameters such as salinity, vertical-to-horizontal permeability ratio, injection rate, bottom hole pressure, and temperature on each carbon dioxide trapping mechanism were analyzed. Results revealed that each carbon dioxide trapping mechanism has a different capacity for storing carbon dioxide and could be either affected linearly or nonlinearly with various parameters. Higher aquifer temperatures are not recommended for carbon dioxide storage because most of the carbon dioxide gas is stored as free gas, which increases the risk of leakage in case of mechanical failure or imbalance. Excess salinity is the only factor that reduces aquifer storage capacity. Furthermore, it was found that an aquifer with a lower vertical-to-horizontal permeability ratio is recommended for carbon dioxide storage because it increases carbon dioxide stored in an immobile phase, which avoids risk leakages. There was an increase of 43.2% and a decrease of 16.84% for minimum and maximum vertical-to-horizontal permeability (kv/kh) ratios, respectively, compared to the base for residual trapping mechanisms. Also, there was a decrease of carbon dioxide dissolved by 19% at maximum kv/kh ratios and an increase of 58% at minimum kv/kh ratios, compared to the base case. Further, there was an increase of carbon dioxide trapped by 96.4% and dissolved by 97% when water was injected at a higher rate compared to the base case (no water injection). Thus, a high injection rate is suggested to enhance residual and solubility trapping mechanisms. It is recommended that the carbon dioxide injection rate and bottom hole pressure be kept at optimal levels to avoid mechanical failure due to aquifer pressures building up, which can increase the risk of leakages and must be monitored and controlled at the surface using pressure gauges or sensor technology.

Investigation of solubility trapping mechanism during geologic CO2 sequestration in Deccan Volcanic Provinces, Saurashtra, Gujarat, India

Solubility of CO2 in connate water plays a crucial role in facilitating the safe disposal of CO2 in geological formations, and this phenomenon in CO2 geological sequestration is termed solubility trapping. A multiphase-reactive transport code that solely considers CO2 dissolution and its accompanying pH fluctuation are used to investigate the influence of the geological and sequestration parameters on a solubility trapping mechanism. A 3-dimensional synthetic geological domain is modelled based on the geological data of Deccan volcanic provinces in Saurashtra, Gujarat, India. The stairsteps kind of morphology of geological formation obtained from literature was considered. Simulation results have shown that parameters such as caprock morphology, petrophysical properties, and injection location significantly affect solubility trapping. Solubility trapping can be observed by examining the pH variation, pressure distribution, and CO2 migration patterns. Analysis of such domains can give foresight about the possible implementation of CO2 sequestration and its influence on the solubility trapping mechanism.

A Sensitivity Study of Salt Concentration in Brine to The Solubility of CO2 in Saline Aquifers

In CO2 sequestration, four main trapping mechanisms are expected such as structural, residual, solubility, and mineral trapping. This paper aims to analyse the impact of salt concentration in brine on the CO2 solubility trapping mechanism in the saline aquifer. The CO2 solubility decreases with salinity. In this study, a sensitivity run will be done on an existing saline aquifer dataset to investigate the impact of salt concentration using the compositional mode simulation approach. Different types of salt will give different levels of CO2 solubility in an Aqueous solution, for example, at isotherm conditions and at increasing pressure, the same amount of NaCl will be more soluble. At the same temperature condition, higher salinity will decrease CO2 solubility with pressure increases and produce a salting-out phenomenon at the near injector area. The reference dataset was completed using the black-oil simulation with the gas-water system, where the CO2 act as the gas phase and brine as the water phase. The black-oil simulator can only handle isotherm and a single salinity value, which is 200,000 ppm in this case. Thus, this study is expected to give more information and improve the solubility trapping mechanism in a saline aquifer.

Influence of Caprock Morphology on Solubility Trapping during CO2 Geological Sequestration

Carbon capture and sequestration (CCS) technology is one of the indispensable alternatives to reduce carbon dioxide (CO2) emissions. In this technology, carbon capture and transport grid will send CO2 to the storage facilities that are using various storage techniques. Geologic carbon sequestration (GCS) is one such storage technique where CO2 is injected into a deep geological subsurface formation. The injected CO2 is permanently stored in the formation due to structural, residual, solubility, and mineral trapping phenomena. Among different trapping mechanisms, solubility trapping plays a significant role in the safe operation of GCS. In this work, the study is conducted to elucidate the influence of top surface caprock morphology on the solubility trapping mechanism. The simulation results show that the naturally available heterogeneous formations with anticline and without anticline structure influence the solubility fingering phenomena and solubility entrapment percentage over a geological time scale. The lateral migration and sweeping efficiency results of both the synthetic domains for the injected CO2 have shown the importance of caprock morphology on solubility trapping and selection of injection rate. Quantification of solubility trapping in two morphological structures revealed that the synthetic domain without anticline morphology had shown higher solubility trapping. In the future, the simulation data using Artificial Neural Networks can be applied to predict the structural and solubility trapping of geological formations. This analysis further helps incorporating the interaction of CO2 with porous media leading to a mineral trapping mechanism.

The use of supercritical CO2 in deep geothermal reservoirs as a working fluid: Insights from coupled THMC modeling

A coupled THMC (thermal-hydrological-mechanical-chemical) model is developed and applied to explore the potential feasibility of using scCO 2 (supercritical carbon dioxide) as a working fluid in geothermal reservoirs . This is achieved by examining the evolution of the kinetics of mineral precipitation-dissolution and its associated impact on the evolution of the rock permeability and porosity. The pH of the reservoir rapidly reduces from 7 to ∼4.5–5 due to the fast dissolution of calcite . Chemical reactions and mineral dissolution and precipitation near the injector are suppressed by the plug-flow penetration of anhydrous scCO 2 displacing the original pore fluid . A conceptual three-zone model is proposed to illustrate the kinetic process of feldspar dissolution and precipitation depending on timing. The initial high concentration of K + prompts feldspar to precipitate in the first stage by consuming K + until 1 y , Feldspar were dissolved into precipitations of illite , smectite , and siderite at 1-6 y , with albite , muscovite and kaolinite mostly precipitated in the last stage 6–10 y . The precipitations of secondary clay minerals and quartz serve to maintain the integrity of caprock sealing. Continuous scCO 2 injection under fully coupled THMC model shows a 1.4-times enhancement of fracture permeability and 1.2-times enhancement of matrix permeability dominated by chemical dissolution and thermal unloading process. The pronounced thermal drawdown is the principal factor in enhancing permeability and porosity near injection well. Furthermore, the expansive capability of CO 2 provides extra benefits in enhancing formation pressure to ensure consistent high flow rates, while achieving a higher thermal energy extraction efficiency and preventing scaling issues in wellbore . The mass concentration of scCO2 in the production well increased to 0.82 after 1.2 × 10 8 s also leads to the enhancement of fluid enthalpy up to 6.5 × 10 5 J/kg, due to the high heat capacity of scCO 2 . The injected CO 2 are sequestered at ∼2 × 10 7 kg at t = 2 × 10 8 s (6.34 y ) as the solubility trapping mechanism.

Compositional Modeling to Analyze the Effect of CH4 on Coupled Carbon Storage and Enhanced Oil Recovery Process

The present study is aimed at the development of compositional simulation models of the co-injection of CO2 and CH4 during the water-alternating-gas (WAG) process in order to assess the efficiency of carbon capture and storage in combination with enhanced oil recovery (CCS-EOR). The co-injection of CO2 and CH4 occupies more reservoir pore volume and causes higher reservoir pressure than CO2 WAG, thus leading to an enhanced early EOR performance. However, the overall EOR performance of the co-injection method becomes lower than that of CO2 WAG due to the reduced miscibility and sweep efficiency upon further CH4 addition. The decrease in gas displacement and sweep efficiency weaken the hysteresis effects upon the residual trapping mechanism. However, the solubility trapping mechanism takes effect because the co-injection generates higher average reservoir pressure than does the CO2 WAG. The index of global warming potential (GWP) in a mole unit is employed to quantify the carbon storage effects of CO2 and co-injection WAG cases. According to the index, 1 mole of CH4 sequestration has the same effects as that of 10 moles of CO2 for global warming mitigation. In conclusion, the carbon storage effects are enhanced as CH4 concentration in the WAG increases.

Hydrophilicity/hydrophobicity driven CO2 solubility in kaolinite nanopores in relation to carbon sequestration

CO2 sequestration into underground aquifers is a viable option to alleviate greenhouse gas emissions. CO2 solubility trapping in nanoporous media saturated with saline water may play an important role. In this process, CO2 solubility in nanoporous media is determined by the mutual interactions among CO2, water, and nano-confinement, which ultimately determines the CO2 sequestration amount. However, the effects of nano-confinement surface characteristics are not studied yet. In this study, we use molecular dynamics simulations to study the effects of surface characteristics on CO2 solubility under nano-confinement by deploying kaolinite nanopores as a model under typical geological conditions (373 K and up to 400 bar). We find that, compared to the bulk solubility, CO2 under-solubility is observed in hydrophilic kaolinite nanopores, while over-solubility is seen in hydrophobic kaolinite nanopores. From the microscopic view, in the hydrophilic kaolinite nanopores, water forms strong adsorption layers on the pore surfaces, which repel CO2 molecules. However, CO2 and water can co-adsorb on the pore surfaces in the hydrophobic kaolinite nanopores. In addition, CO2 molecules align parallel to the pore surface in hydrophobic kaolinite nanopores, while water molecules align perpendicular to the hydrophilic one. CO2 is less hydrated under the nano-confinement than in bulk, especially under the hydrophobic one. In conclusion, hydrophobic strata are more capable to sequestrate CO2 than hydrophilic strata in terms of solubility trapping mechanism.

Solubility trapping as a potential secondary mechanism for CO2 sequestration during enhanced gas recovery by CO2 injection in conventional natural gas reservoirs: An experimental approach

This study aims to experimentally investigate the potential of solubility trapping mechanism in increasing CO2 storage during EGR by CO2 injection and sequestration in conventional natural gas reservoirs. A laboratory core flooding process was carried out to simulate EGR on a sandstone core at 0, 5, 10 wt% NaCl formation water salinity at 1300 psig, 50 °C and 0.3 ml/min injection rate. The results show that CO2 storage capacity was improved significantly when solubility trapping was considered. Lower connate water salinities (0 and 5 wt%) showed higher CO2 solubility from IFT measurements. With 10% connate water salinity, the highest accumulation of the CO2 in the reservoir was realised with about 63% of the total CO2 injected stored; an indication of improved storage capacity. Therefore, solubility trapping can potentially increase the CO2 storage capacity of the gas reservoir by serving as a secondary trapping mechanism in addition to the primary structural and stratigraphic trapping and improving CH4 recovery.

The effect of WACO2 ratio on CO2 geo-sequestration efficiency in homogeneous reservoirs

Various factors such as reservoir temperature, wettability, caprock properties, vertical to horizontal permeability ratio, salinity, reservoir heterogeneity, injection well configuration affect the CO2 geo-sequestration efficiency. Furthermore, it was previously investigated that CO2 storage efficiency can be improved by using water alternating CO2 (WACO2) technology. However, the effect of the WACO2 ratio (the ratio of the total amount of injected CO2 to the total amount of injected water) on CO2 storage efficiency has not been addressed adequately. Thus, in this paper, a 3D homogeneous reservoir simulation model has been developed to study the impact of the WACO2 ratio on CO2 mobility and CO2 trapping capacity using five different WACO2 ratios (i.e. 3, 2, 1, 1/2, and 1/3). For all WACO2 ratios tested, 9000 kton (kt) of CO2 were injected during 3 CO2 injection cycles (2 years each) and at an injection rate of 1500 kt per year. Each CO2 injection cycle was followed by a 2 years water injection cycle with injection rates of 500 kt/year, 750 kt/year, 1500 kt/year, 3000 kt/year, and 4500 kt/year for the 3, 2, 1, 1/2, and 1/3 WACO2 ratios, respectively. Then, this 12 years WACO2 injection period was followed by a 100 years post-injection period. Our results clearly indicate, after 100 years post-injection period, that the WACO2 ratio has an important effect on the CO2 migration distance, CO2 mobility and CO2 trapping capacity. The results demonstrate that lower WACO2 ratio leads to reduce the vertical CO2 plume migration and CO2 mobility. Furthermore, low WACO2 ratio enhances the capacities of capillary and solubility trapping mechanisms. Thus, we conclude that WACO2 has a significant impact on the geo-sequestration efficiency and less WACO2 ratios are preferable

Exploring safe disposal of CO2 and wastewater in saline aquifers

Process safety has taken the spotlight in recent years for both carbon sequestration and wastewater disposal operations. We present a systematic approach to monitoring injection-well performance in saline aquifers for both wastewater disposal and CO2 injection with required well surveillance and injection data. Uncertainty assessment formed the cornerstone of understanding the fundamental variables impacting the injection performance with numerical modeling. Among the variables studied, aquifer heterogeneity and injection parameters, rock compressibility, and fracture gradient have a significant influence on total cumulative injection and safe-volume injection.The modified-Hall analysis turned out to be the critical diagnostic tool for identifying the abnormal injection behavior and real-time disposal process for both fluids. We estimated the safe pore-volume injection for disposal of wastewater and CO2 to be 1.6% and 1.5%, respectively, in saline aquifers at 80% probability. Of the CO2 trapping mechanisms studied here, critical gas saturation turned out to be the most dominant in residual trapping mechanism, whereas porosity and brine salinity appeared dominant in solubility trapping mechanism.

Effects of gas relative permeability hysteresis and solubility on associated CO2 storage performance

CO2 enhanced oil recovery (EOR) has been carried out in the Bell Creek oil field since 2013. Together with the encouraging oil production results, a considerable quantity of CO2 has also been trapped in the reservoir as a normal part of the EOR process, also referred to as associated storage. Because of the complex geologic conditions in the field, a series of experimental and modeling work have been conducted to better understand the CO2 EOR and associated storage performance in the reservoir. Effects of gas relative permeability hysteresis and solubility on associated CO2 storage performance are thoroughly investigated in this study.A proportion of injected CO2 remains behind through residual and solubility trapping mechanisms when CO2 flows through a reservoir during a CO2 EOR process. Over 50 core plugs were collected from the reservoir to characterize the rock properties. Mineralogical analysis and capillary pressure measurements showed that the mineral composition and pore-size distribution in the reservoir are favorable for residual trapping of CO2. The hysteresis of gas relative permeability was measured to assess the effect of residual trapping on associated CO2 storage using steady-state relative permeability tests and reservoir simulation. The reservoir oil was characterized based on pressure–volume–temperature experiments and Peng–Robinson equation of state modeling, which showed that CO2 solubility in oil is much greater (≥5 times) than in water. Results indicated that depleted oil reservoirs have great potential to store a huge quantity of CO2 associated with EOR operations, as residual oil saturation is 0.3 or greater in most conventional oil reservoirs after water flooding.

Effects of ultrasonic waves on carbon dioxide solubility in brine at different pressures and temperatures

The adverse impacts of CO2 emission on the global warming highlight the importance of carbon capture and storage technology and geological storage of CO2 under solubility trapping mechanisms. Enhancing the solubility of CO2 in formation water has always been the focus of research in the area of CO2 sequestration. Ultrasound techniques are one of the environmentally friendly methods that use high-intensity acoustic waves to improve gas solubility in liquids. Ultrasonic waves can alter the properties of different phases that lead to chemical reactions and provide a means to increase the solubility of CO2 in connate water. In this study, we investigated the effects of ultrasound on the solubility of CO2 in connate water under different conditions of pressure, temperature, and salinity. The results showed that the solubility of CO2 was improved with increasing pressure under ultrasonic effects. However, the solubility of CO2 was inversely proportional to the increase in brine salinity and temperature. Therefore, it was concluded that the solubility of CO2 might be enhanced in the presence of ultrasound.

Prediction of storage efficiency on CO2 sequestration in deep saline aquifers using artificial neural network

This study presents the application of artificial neural network (ANN) to predict storage efficiency of CO2 sequestration in deep saline aquifers. To a create training database used as input and output neurons in ANN, sensitivity analysis of parameters considering the aquifer characteristics was performed by numerical simulation. Based on the analysis, the factors and their ranges influencing CO2 sequestration in deep saline aquifers were determined and 150 representative realizations used as a training database were generated with trapping indices of the residual CO2 and solubility trapping mechanisms. The ANN model was designed with optimum architecture minimizing the mean squared error (MSE) for testing data set and it was tested with validation samples. The results showed that the proposed ANN model had a high prediction performance with a high coefficient of determination (R2) of over 0.99 on comparing with the target values, a low MAPE (mean absolute percentage error) of 1.26%, and RMSE (root mean square error) of 0.41 for TEI (total trapping efficiency index). As a field application, the model has also been evaluated with the field scale data on the Gorae V structure in Block VI-1, Korea. The results of prediction were well matched with the targeted values and accuracy between the ANN predictions and field scale data was achieved with a high coefficient of determination (R2) of more than 0.96, a low MAPE of 4.40%, and RMSE of 3.58 for TEI. From these results, it is believed that the newly developed ANN model can predict storage efficiency with high accuracy and it can also be considered as a useful and robust tool to evaluate the feasibility of CO2 sequestration in deep saline aquifers.

A numerical study of the impurity effects of nitrogen and sulfur dioxide on the solubility trapping of carbon dioxide geological storage

Three-dimensional numerical simulations are performed to investigate the effects of nitrogen (N2) and sulfur dioxide (SO2) impurities on the solubility trapping mechanism of carbon dioxide (CO2) geological storage. Dissolved CO2 has been suggested to increase the density of the aqueous phase. Results from this study indicate that, when dissolved in the formation water, certain level of the N2 impurity contained in the CO2 streams reduces the density increase, which is the driving force of convection. With a higher N2 concentration, the onset of convection is later and the dissolution rate is smaller. The decay time of convection for the higher N2 concentration case is also delayed. For the co-injection of CO2 and N2, total CO2 dissolved in the formation fluids is less than that of injecting CO2 alone. During the timescale of dissolution, the mobile and buoyant CO2 streams have the potential to leak through the caprock to the atmosphere. It is necessary to reinforce the risk management for safe CO2 storage for the co-injection of CO2 and N2. In contrary to N2, the SO2 impurity is implied to enhance the solubility trapping mechanism and it has more significant effects compared to N2 at the same impurity concentration.

Algorithm for determining optimum sequestration depth of CO2 trapped by residual gas and solubility trapping mechanisms in a deep saline formation

AbstractAn algorithm is proposed here for determining the optimum sequestration depth (in terms of depth corresponding to maximum net income per unit rock volume) in a saline formation for CO2 trapped by residual gas and solubility trapping mechanisms. The Peng–Robinson equation of state was used to determine the density and fugacity of sequestered CO2 and the compression energy required for CO2 injection. Geochemist’s Workbench®, a commercial geochemical software package, was used to estimate CO2 solubility in groundwater. Operational costs and CO2 emissions due to compression energy consumption were estimated. A hypothetical reference case was constructed to illustrate the proposed algorithm, assuming constant values of geothermal gradient, hydrostatic pressure gradient, sweep efficiency and initial groundwater chemistry, with a depth‐dependent porosity and porosity‐dependent saturation of residual gas. In general, the algorithm was illustrated successfully for the hypothetical reference case and produced the following results. The depth corresponding to maximum trapping capacity was approximately 3000 m, but the depth representing maximum net income was approximately 1300 m. CO2 emissions due to compression energy consumption per unit mass of CO2 sequestration cannot be ignored, but may be <0.15, even down to a depth of 7000 m. Both the trapping capacity and net income of CO2 sequestration decreased with geothermal gradient, but the corresponding optimum depths increased with geothermal gradient.