Sequestration In Saline Aquifers Research Articles

Fully coupled THM modeling of CO2 sequestration in depleted gas reservoirs considering the mutual solubilities in CO2-Hydrocarbon gas-brine systems

In recent years, CO2 geological sequestration has gained significant traction as a viable solution for mitigating global emissions. However, assessing such processes has been challenging due to its inherent complexity. Given the extensive temporal and spatial scales, numerical modeling has emerged as the most efficient and cost-effective means of evaluating them. At present, most existing models are tailored for CO2 sequestration in saline aquifers. There are relatively few models available for depleted gas reservoirs, and only a fraction of them possess the capability to account for geomechanical coupling or complex natural gas compositions.CO2 sequestration in depleted gas reservoirs is considered a promising technique for combating global warming. The use of depleted gas reservoirs has several advantages over saline aquifers, such as the availability of existing facilities and the proven capacity and stability of gas storage. It is believed that CO2 storage in depleted petroleum reservoirs can provide intermediate-scale storage until large-scale storage in saline aquifers becomes mature.Here we propose an Equation of State (EOS) module for CO2 sequestration in depleted gas reservoirs or CO2-enhanced gas recovery. It takes into consideration the mutual solubilities in the CO2-hydrocarbon gas-brine system based on the equality of the chemical potentials of the aqueous and non-aqueous phases. In such a way, it can properly address CO2 dissolution into brine when hydrocarbon gas is present. Hydrocarbon gas includes methane, ethane, and propane. It employs well-recognized approaches to calculate the thermodynamic properties of the gaseous and aqueous phases. This EOS module has been applied to our in-house simulator, TOUGH2-CSM, to enable thermo-hydrological-mechanical modeling. Our research could fill the gap and provide a reference for future studies in this regard.

Reciprocal cross‐correlation analysis of two‐phase seepage processes and reservoir heterogeneities in CO2 saline aquifer sequestration

AbstractWhen CO2 saline aquifer storage is carried out, the heterogeneity of reservoir rock is an important factor affecting CO2 transport, and the reservoir heterogeneity in numerical simulations is mainly manifested as the heterogeneity of the parameter field. Since the parameter distributions across the reservoir are not available with the existing probes, the stochastic finite element method is combined with a two‐phase flow model to establish an unconditional random field of permeability, and computations are performed using the Monte Carlo method. The permeability, CO2 maximum migration distance (Md) and CO2 sweep area (Sa) were analyzed for mutual correlation. The permeability correlation area affecting Md and Sa was obtained, and the changes in the correlation area under the coefficient of variation (Cv) and correlation length (λx) of the permeability field in the different reservoirs were analyzed. The kriging superposition approach (KSA) was subsequently used to estimate both the Md and Sa of the target reservoir by establishing conditional random fields based on the sampling parameters in regions with different correlations, resulting in errors of 0.66% for Md and 0.96% for Sa in the high correlation region and 4.86% and 3.12% for Md and Sa in the low correlation region, which suggested that the sampling results from the high correlation region were less biased in the estimation. Under limited sampling conditions, it is recommended that samples be collected in regions with high correlations to reduce the uncertainty of CO2 transport analysis due to unknown heterogeneity. © 2024 Society of Chemical Industry and John Wiley & Sons, Ltd.

Application of biopolysaccharide green foam fluid to enhance CO2 sequestration in high-temperature and high-salinity saline aquifer

Saline aquifer, a geological body, is widely distributed in the world and has high CO2 sequestration potential. Due to the large differences in viscosity and density between the CO2 and brine and the micro-heterogeneity of the saline aquifer, CO2 override, and viscous fingering may occur in strata, resulting in low CO2 sequestration efficiency. Following the concept of green chemistry, this study formulated CO2 foam using biopolysaccharides and a green surfactant alkyl polyglycosides (APG), to enhance the CO2 sequestration efficiency in saline aquifers. The ability of three biopolysaccharides (diutan gum, welan gum and xanthan gum) to stabilize CO2 foam was explored. According to the foam drainage activation energy and the Ostwald ripening rate, the CO2 foam with diutan gum as the stabilizer and APG as the foaming agent exhibited the favorable performance. The mechanism of diutan gum stabilizing CO2 foam was analyzed through studies on intermolecular interactions, interfacial properties, rheology, and micromorphology studies. We then investigated the effects of foam quality and flow rate on the CO2 foam rheology in sandstone cores by analyzing the changes in CO2 saturation, the matching relationship between bubble diameters under different conditions and sandstone core pore size, and the variation in foam rheology was explained. Furthermore, the ability of CO2 foam to enhance CO2 sequestration was explored in saline aquifers using core-nuclear magnetic resonance techniques. CO2 foam largely reduces the water saturation of macropores and establishes high-seepage resistance to facilitate CO2 foam diversion to the meso- and micropores. This fully leverages the space in these pores to store CO2 and greatly improves CO2 sequestration in saline aquifers.

Interfacial chemical mechanisms of brine salinity affecting the CO2 foam stability and its effect on the sequestration capacity of CO2 in deep saline aquifer

CO2 foam flooding is an important method to expand the sweep scope of CO2 and significantly improve the ability of sequestrate CO2 in saline aquifer. Salinity is an important factor affecting the CO2 foam stability. In this study, it was found that the stability of CO2 foam prepared by alkyl polyglycoside APG-0810 was effectively improved by increasing the salinity. Molecular dynamics studies showed that increasing salinity promoted the adsorption of APG-0810 molecules at the CO2-water interface and enhanced the degree of inter-entanglement between alkyl chain segments, which dramatically increasing the CO2-water interfacial activity and liquid film strength. The enrichment degree of metal ions around the APG-0810 hydrophilic group also enhanced with the increase of salinity, which improves the disjoining pressure of the bubble liquid film. The binding ability of the hydrophobic groups of APG-0810 on CO2 molecules was enhanced, which inhibited the diffusion process of CO2 molecules inside the bubble. Subsequently, the influence rules of salinity on the CO2 foam rheology in the core were studied, and finds that increasing salinity increase the transition foam quality and the corresponding maximum viscosity. The improvement of liquid film strength reduces the probability of bubble aggregation inside the core, allowing a sufficient number of small-sized bubbles to be trapped by the pores, strengthening the superposition of Jamin effect and expanding the CO2 sweep scope in saline aquifer. In addition, we found that the zero-shear viscosity and yield stress of CO2 foam are positively correlated with salinity, which means that CO2 foam has a higher blocking ability for preferential channel for high-salinity saline aquifer, and the bubble cluster trapped by the capillary force will have a higher starting-pressure, improving the safety of CO2 sequestration in saline aquifer.

Experimental investigation of salt precipitation behavior and its impact on injectivity under variable injection operating conditions

During the CO2 geological sequestration in saline aquifers, salt precipitation issues can diminish reservoir injectivity and significantly escalate injection costs. Variations in the gas supply during injection can lead to fluctuations in CO2 injection rates. These abrupt changes in injection parameters can affect the distribution of reservoir pressures and brine migration behavior, subsequently influencing salt precipitation dynamics. This study employs a designed micromodel with representative geological boundary conditions to investigate salt precipitation behavior under variable injection conditions, and the experimental conditions are at atmospheric pressure and 50 °C. The flow rates of the CO2 injection flow rates range from 0.5 mL/min to 4 mL/min. The findings reveal that under variable injection conditions, changes in gas injection rates can induce fluctuations in the reservoir solution, leading to the formation of “wet salt barriers” characterized by clustered salt growth near the inlet. This phenomenon significantly impairs injectivity. When sufficient supplemental solution is introduced, most of the previously precipitated salt is initially dissolved, eventually reaching a dynamic equilibrium that restricts further salt growth. However, under conditions of limited supplemental solution, salt precipitation predominates, and salt can proliferate, further impacting injectivity. This paper proposes a variable injection strategy to mitigate the impact of salt precipitation on injectivity. It recommends transitioning from low to high flow injection rates as early as possible to prevent the reflow of the solution near the injection interface, thereby minimizing salt accumulation and its adverse effects on injectivity.

CO2 soluble surfactants for carbon storage in carbonate saline aquifers with achievable injectivity: Implications from the continuous CO2 injection study

Continuous CO2 injection (CCI) into saline aquifers suffers from low sweep efficiency. While utilizing foam can effectively address this issue, a relatively potent foam design may undesirably reduce the injectivity of CO2. In this study, the potential of CO2-soluble surfactants assisted carbon storage in carbonate saline aquifers was evaluated by core flooding tests and numerical simulations. It is found that foam can be generated at the displacement front during continuous CO2 injection with 0.39 g/L surfactant (CCI + S, fg = 100 %). The CO2 saturation can reach 60 % after 1.0 pore volume of CCI + S, approximately 50 % higher than that of CCI. The maximum pressure gradient is around 1.5 psi/ft at an injection rate of 1.0 ft/d in 162 mD Indiana Limestone for CCI + S. The effects of surfactant concentration, foam quality, and rock permeability were also investigated by core flooding. Moreover, the influence of surfactant partitioning and adsorption on CO2 transport behavior was systematically evaluated by numerical simulation in synthetic and geological models, using modeling parameters that are realistic for field applications. The advantage of injecting surfactant with CO2 is more evident in heterogeneous saline aquifers. Such novel injection strategy provides a promising approach for carbon sequestration in saline aquifers by controlling the mobility of CO2 at the displacement front and simultaneously maintaining acceptable injectivity in the field. The CCI + S process may also impose less risk to the caprock. Expanding the potential CO2 storage sites to heterogeneous saline aquifers could be a game-changer. Our understanding of foam dynamics in porous media could also be advanced.

A Study on the Dissolution Behavior of Typical Minerals in Continental Deposited Reservoirs during CO2 Geological Storage

CO2 sequestration in saline aquifers is one of the most potential sequestration modes, and saline aquifers are ideal sites for CO2 geological sequestration. After CO2 is injected into a saline aquifer, it will have a long-term complex geochemical reaction with the formation of minerals and water, and the minerals will undergo multiple reactions such as dissolution and reprecipitation. Therefore, an in-depth study of the geochemical reaction mechanisms between CO2 and formation minerals is of great significance to the accurate calculation and prediction of CO2 storage volume and the safety evaluation of long-term CO2 sequestration. In China, continental saline aquifers are widely distributed, whose mineral compositions and texture maturity are markedly different from those of the marine sedimentary basins in North America, and their stratigraphic environments are more complicated. The studies on the CO2–water–rock (mineral) still have many research gaps or insufficiencies, and there is no report on the dissolution mechanisms of individual minerals in the reaction. Taking one certain block of Daqing Oilfield, which is a typical continental deposit in China, as an example, we analyze the dissolution laws and four types of typical continental deposited minerals under the effect of CO2 and the change features of ionic compositions and pH of the formation water in the process of geochemical reaction. The research results indicate that CO2 has different dissolution degrees for the four types of minerals, among which, feldspar, as the main mineral in continental sedimentary formations, has the lowest dissolution rate. Furthermore, in terms of the water type (Na+-enriched NaHCO3) of the saline aquifer in the deep part of the continental deposit, feldspar can precipitate into the secondary minerals represented by dawsonite in the later stage, which can act as the potential minerals of carbon fixation to increase the CO2 mineralization storage volume in continental deposited saline aquifers.

Molecular dynamics and experimental study of the effect of pressure on CO2 foam stability and its effect on the sequestration capacity of CO2 in saline aquifer

CO2 foam flooding technology is one of the important methods to improve the efficiency of CO2 sequestration in saline aquifers. This article explores the influence rules of pressure on CO2 foam stability and its micro-mechanisms, and its effect on the efficiency of CO2 foam to enhance CO2 sequestration. Increasing pressure is conducive to delaying the foam drainage and inhibiting CO2 diffusion between the liquid films, micro-mechanisms showed that the binding effect of surfactants on water and CO2 molecules was enhanced due to increased pressure. Then core-nuclear magnetic resonance was used to study the effect of pressure on CO2 sequestration characteristics from core scale, the bubble population accumulation in the macropores increased with the enhanced pressure, promoting the diversion effect of foam to the meso- and micropores. In addition to enhancing the CO2 sequestration potential of the macropores, the utilization of storage space of meso- and micropores was improved.

Integrated Formation Evaluation for Site-Specific Evaluation, Optimization, and Permitting of Carbon Storage Projects

Participation in over 80 carbon capture and sequestration (CCS) projects spanning 25 years has led to the evolution of a recommended well-based appraisal workflow for CO2 sequestration in saline aquifers. Interpretation methods are expressly adapted for CCS applications to resolve key reservoir parameters, constrain field-scale modeling, provide answers required for the permitting process, and de-risk unique CCS evaluation challenges, such as Storage capacity Injectivity Containment. A challenge complicating all of the above is the eventual impact of three-way interaction among rock matrix, brine, and (impure) CO2 streams. Most logging, sampling, and laboratory techniques are adapted from established domains such as enhanced oil recovery, underground gas storage, and unconventional reservoir evaluation, though some CCS-specific innovation is also needed. Storage evaluation begins with established methods for lithology, porosity, permeability, and pressure, while special core analysis (SCAL) determines CO2 storage efficiency and relative permeability. Containment evaluation spans multiple disciplines and methods: the petrophysicist’s task to quantify seal capacity relies heavily on laboratory analysis, while geologists leverage downhole imaging tools to verify caprock structural/tectonic integrity. Geomechanics engineers define safe injection pressure via mechanical earth models (MEMs) built on advanced acoustic logs calibrated by core geomechanics, wellbore failure observations, and in-situ stress tests. The impact of rock-brine-CO2 interactions is studied via custom SCAL experiments and/or pore-scale digital rock simulations that rigorously represent chemical and thermal processes. Wireline formation tester samples provide representative formation brine as feedstock for SCAL. Water samples also enable operators to prove injection within regulatory limits while establishing baselines for future monitoring programs. Examples applied to recent CCS projects in North America are presented. All of the above data need to be integrated into a CCS model predicting the CO2 plume behavior across the area of interest and within multiple horizons.

Numerical Simulation of a Thermal-Hydraulic-Chemical Multiphase Flow Model for $$\hbox {CO}_2$$ Sequestration in Saline Aquifers

Numerical Simulation of a Thermal-Hydraulic-Chemical Multiphase Flow Model for $$\hbox {CO}_2$$ Sequestration in Saline Aquifers

The Impact of Relative Permeability Hysteresis on CO2 Sequestration in Saline Aquifer

This work analyzed the amount of capillary-trapped CO2 for maximum residual gas saturation due to relative permeability hysteresis. Upward migration of CO2 is unwanted because it increases the risk of CO2 migration from storage sites to the surface. One way to mitigate CO2 leakage risk is to reduce the vertical CO2 migration to improved storage capacity and containment security. A compositional simulator (CMG-GEM) was used to simulate the flow of two components (CO2 and H2 O). A fluid model was built with the PR 78 EOS using WINPROP. A base case model without relative permeability hysteresis was simulated and compared with the case with relative permeability hysteresis. The amount of CO2 trapped, and CO2 saturation distribution were analyzed for maximum trapped gas saturation of 0.3, 0.4 and 0.5. Results shows an increase in the amount of CO2 trapped as the maximum residual gas saturation was increased from 0.3 to 0.4 and 0.5 with a value of 16560128mol for the base case study, 49041744mol, 59502924mol and 67286728mol respectively for maximum residual gas saturation due to relative permeability hysteresis of 0.3, 0.4 and 0.5 respectively. Very little accumulation of CO2 occurs when the maximum trapped gas saturation due to relative permeability hysteresis was set at 0.5. Result reveals that after 200 years, almost all the CO2 was trapped in the formation. Therefore, the imbibition cycle at the trailing end of the CO2 plume should be considered as accounting for hysteresis effects has led to a spread-out distrib

Density-Driven Convection for CO2 Solubility Trapping in Saline Aquifers: Modeling and Influencing Factors

Industrial development has significantly increased the concentration of CO2 in the atmosphere, resulting in the greenhouse effect that harms the global climate and human health. CO2 sequestration in saline aquifers is considered to be one of the efficient ways to eliminate atmospheric CO2 levels. As an important mechanism, the solubility trapping greatly determines the efficiency of CO2 sequestration in saline aquifers, and this depends, in turn, on the density-driven convection that occurs during the sequestration. Density-driven convection is influenced by multiple factors. However, existing discussions on some of these influential factors are still ambiguous or even reach contradictory conclusions. This review summarizes the common modeling approaches and the influence of factors on density-driven convection. We suggest that saline aquifers with high values of depth, permeability, pH, and SO2 impurity concentration are the ideal CO2 sequestration sites. A certain degree of porosity, fractures, stratification, slope, hydrodynamic dispersion, background flow, and formation pressure are also considered advantageous. Meanwhile, the geological formation of the Permian White Rim Sandstone or carbonate is important, but it should not contain brine with excessive viscosity and salinity. Finally, we discuss the contents in need of further research.

Expansion of Geological CO2 Storage Capacity in a Closed Aquifer by Simultaneous Brine Production with CO2 Injection

Structural trapping is the primary mechanism for intensive CO2 sequestration in saline aquifers. This is the foundation for increasing global CO2 storage; gradual switch to preferable trapping mechanisms, such as residual saturation, dissolution, and mineral trapping, will require a long-time scale. The major constraints limiting the storage capacity of structural trapping are formation pressure and structure size. Over-pressure owing to CO2 injection causes a disruption of seal integrity indicating a failure in geological sequestration. The other constraint on storage capacity is a spill point determining geological storage volume. Overflowing CO2, after filling the storage volume, migrates upward along the aquifer geometry with buoyancy. This study proposes a methodology to maximize CO2 storage capacity of a geological site with a substructure created by an interbedded calcareous layer below spill point. This study provides various conceptual schemes, i.e., no brine production, simultaneous brine production and pre-injection brine production, for geological CO2 storage. By the comparative analysis, location of brine producer, production rate, and distance between injector and producer are optimized. Therefore, the proposed scheme can enhance CO2 storage capacity by 68% beyond the pressure and migration limits by steering CO2 plume and managing formation pressure.

Numerical Simulation of Carbon Dioxide–Nitrogen Mixture Dissolution in Water-Saturated Porous Media: Considering Cross-Diffusion Effects

The possibility of impure carbon dioxide (CO2) sequestration can reduce the cost of these projects and facilitate their widespread adoption. Despite this, there are a limited number of studies that address impure CO2 sequestration aspects. In this study, we examine the convection–diffusion process of the CO2–nitrogen (N2) mixture dissolution in water-saturated porous media through numerical simulations. Cross-diffusion values, as the missing parameters in previous studies, are considered here to see the impact of N2 impurity on dissolution trapping in more realistic conditions. Homogeneous porous media are used to examine this impact without side effects from the heterogeneity, and then simulations are extended to heterogeneous porous media, which are a good representative of the real fields. Heterogeneity in the permeability field is generated with sequential Gaussian simulation. Using the averaged dissolved CO2 and dissolution fluxes for each case, we could determine the onset of different dissolution regimes and behaviors of dissolution fluxes in CO2–N2 mixture dissolution processes. The results show that there is a notable difference between the pure cases and impure cases. Additionally, a failure to recognize the changes in the diffusion matrix and cross-diffusion effects can result in significant errors in the dissolution process. At lower temperatures, the N2 impurity decreases the amount and flux of CO2 dissolution; however, at higher temperatures, sequestrating the CO2–N2 mixture would be a more reasonable choice due to enhancing the dissolution behavior and lowering the project costs. The results of the heterogeneous cases indicate that heterogeneity, in most cases, reduces the averaged dissolved CO2, and dissolution flux and impedes the onset of convection. We believe that the results of this study set a basis for future studies regarding the CO2–N2 mixture sequestration in saline aquifers.

Well‐based monitoring of CO2 geological sequestration operations in saline aquifers: Critical insights into key questions

Geological carbon sequestration in saline aquifers is one of the most promising strategies to help mitigate emissions of CO2 to the atmosphere. Significant challenges in ensuring the security of the sequestration process rest in the evolution and expansion of the CO2 plume in the subsurface. The ability to track the movement of the injected CO2 poses another challenge. Critical questions related to the integrity of the sequestration operations in saline aquifers relate to plume characteristics that can we monitor using well-based variables. We addressed this and related questions using an integrated modeling framework through a numerical investigation of carbon sequestration in saline aquifers during long-term and post-injection periods. This modeling paradigm incorporates the effect of structural, geological, and petrophysical characteristics. That way, we can account for critical physicochemical processes, rock-fluid interactions, and lithology dependencies. The well fluid variables investigated include fluid composition, pH, fluid density, and ion activity. We learned that fluid property analytics and diagnostics can be powerful tools to estimate the movement of CO2 and its storage in different trapping mechanisms. These analytics can help optimize operational aspects and simplify reservoir-scale models while still reflecting the complex nature of the CO2 interactions underground and offering insights into plume evolution.

An analytical approach to the technical and economical optimization of CO2 sequestration in saline aquifers with simultaneous brine production

In the course of developing innovative approaches for climate change mitigation, CO2 sequestration in saline aquifers has drawn attention to itself as an appealing and effective procedure. Simultaneous brine production facilitates storage capacity enhancement in aquifers through formation depressurization. This study is devoted to developing an analytical optimization model for CO2 sequestration projects with simultaneous brine production from a technical and economical perspective. While previous studies have provided analytical optimization models for simple CO2 injection scenarios, this research aims to improve the former models by utilizing more precise transient pressure calculation formulations, up-to-date economic analysis and extending the models to also account for simultaneous brine production in CO2 storage projects. Through this model, the effect of different design parameters including well spacing, the number of injection and production wells, production-to-injection ratio, and carbon revenue can be assessed on the project's storage capacity and net revenue. Subsequently, the design parameters for the most environmentally and financially beneficial scenarios can be identified. The developed optimization model can serve as a fast and accurate pre-implementation tool for the case by case assessment and comparison of different CO2 sequestration project designs. In order to put the model to test, the developed multi-well pressure evolution formulation is used to predict pressure changes in a synthetic aquifer formation throughout several sequestration projects. This profile is then compared with numerical simulation results. The maximum CO2 injection rate and thus storage capacity for numerous project designs is then calculated based on a correlation between a reference injection rate, the time-dependant pressure profile for this rate and the aquifer's formation fracture pressure. Finally the effect of different design parameters is assessed on the storage capacity and net revenue and the fundamentals of selecting the best project design is discussed.

Review of CO2 sequestration mechanism in saline aquifers

The concentration of CO2 in the global atmosphere, which is increasingly annually with continued industrial development, affects both the global climate and the ecological environment. To control the concentration of atmospheric CO2, various methods of carbon capture and sequestration have been proposed and continue to be developed. Among them, CO2 sequestration in saline aquifers has potential for effective high-capacity carbon storage. This work reviews both the research status of structural, residual, solubility, and mineral CO2 sequestration in saline aquifers, and the research progress associated with the integrity of cement sheaths and caprocks. The findings indicate that structural sequestration research must comprehensively consider the influence of various factors, and that the capacity of structural sequestration must be evaluated based on the actual geological conditions of the saline aquifer, caprock properties, and CO2 injection rate. The heterogeneity of the caprock and dynamic changes of CO2 concentration are not considered in current simulations of the effect of chemical interaction between CO2-rich brine and the caprock. Residual sequestration and solubility sequestration are mutually interactive; therefore, exploration of the residual sequestration mechanism must consider the impact of solubility sequestration. Models for simulation of CO2 solubility sequestration in an entire saline aquifer should be developed to reservoir scale and must consider reservoir heterogeneity.

Effect of permeability heterogeneity on the dissolution process during carbon dioxide sequestration in saline aquifers: two-and three-dimensional structures

The convection–diffusion process of carbon dioxide (CO2) dissolution in a saline reservoir is investigated to shed light on the effects of the permeability heterogeneity. Using sequential Gaussian simulation method, random permeability fields in two and three-dimension (2D and 3D) structures are generated. Quantitative (average amount of the dissolved CO2 and dissolution flux) and qualitative (pattern of the dissolved CO2 and velocity streamlines) measurements are used to investigate the results. A 3D structure shows a slightly higher dissolution flux than a 2D structure in the homogeneous condition. Results in the random permeability fields in 2D indicates an increase in the standard deviation of the permeability nodes enhances the dissolution efficiency, fluctuations in CO2 dissolution flux, separation between the different realizations from the same input parameters, and tendency toward more jagged convective fingers’ shape. Furthermore, the distance between the permeability nodes increases the convective fingers’ dissolution efficiency and jagged structure. The degree of freedom in 3D structures results in a higher chance of escaping from the low permeability zones and reduces the interactions between convective fingers in 3D systems. With the same variance and correlation length between permeability nodes, connectivity between high permeable zones in 3D cases are less than that of 2D cases; therefore, 2D realizations overestimate the dissolution flux of real heterogeneous 3D structures, which should be considered carefully.Article HighlightsCO2 sequestration in two and three dimensional heterogeneous saline aquifers are investigated.3D structures in homogeneous conditions show higher dissolution than 2D structures.2D realizations overestimates the dissolution flux over real heterogeneous 3D reservoirs.

Competitive Effects of Permeability and Gravity on the Drying-Out Process during CO2 Geological Sequestration in Saline Aquifers

Abstract Salt precipitation from the drying-out process has a profound effect on the well injectivity during the storage of carbon dioxide (CO2) in deep saline aquifers. Both gravity and reservoir heterogeneity have a significant impact on CO2-plume behavior and CO2 storage capacities. The collective effect of gravity and heterogeneity on the drying-out process by site-scale numerical simulation based on the Sleipner project had been investigated. Three site-scale permeability heterogeneous models and a fracture model had been built; simulation results showed that the gravity effect significantly increased the solid saturation at the injection well in the homogeneous model; changing the position of the injection well can change the distance that gravity can act and affect the amount of salt precipitation near the injection well. A novel conclusion is gravity and heterogeneity showed a mutual resistance relationship when considering the collective effect of gravity and heterogeneity on solid saturation. Gravity effects reduced the amount of salt deposited in the fracture model; at low CO2 injection rate, gravity force dominated CO2 flow; increased rock heterogeneity suppressed the production of salt precipitates; at high CO2 injection rate, viscous force dominated flow; and increased heterogeneity increased salt precipitation. This research is of important guiding significance for the design of site screening and injection schemes from the perspective of avoiding a large amount of salt precipitation and pressure build-up.

Insights from molecular dynamics on CO2 diffusion coefficient in saline water over a wide range of temperatures, pressures, and salinity: CO2 geological storage implications

Successful design and execution of CO2 sequestration in saline aquifers requires a comprehensive understanding of CO2 transport properties. CO2 diffusion coefficient affects CO2 dissolution behavior in water/brine and controls phenomena such as shape of viscous fingers and onset of instabilities. Experimental determination of CO2 diffusion coefficient is a technically and economically challenging task. In this research work, we used Molecular Dynamics (MD) simulation to compute CO2 diffusion coefficient in various NaCl saline water concentrations (1–6 mol NaCl/kg water) under a broad range of temperatures (294–423 K) and pressures (10–30 MPa) to acquire a data set for CO2 diffusion coefficient in different conditions. According to the results, NaCl concentration increase gives rise to a decrease in CO2 diffusion coefficient by 15%, 29%, 49%, and 64% at 1 M, 2 M, 4 M, and 6 M solutions, respectively, compared to pure water. Presence of more cations due to salinity increase forms further hydration shells act as a barrier for CO2 diffusion. In addition, the rise in CO2 diffusion at elevated temperatures can be explained by the cation's hydration shell size reduction with temperature increment due to intensifying repulsive forces among water molecules. We proposed a new precise correlation for estimation of CO2 diffusion coefficients over temperatures and salinity ranges of this study. Regarding the pressure variation effects, no tangible changes were observed with pressure increase, validating a negligible influence on diffusion coefficient. Furthermore, the CO2 diffusion coefficient variability in presence of other salts, namely MgCl2, CaCl2, KCl, and Na2SO4, were computed separately. Comparing the influence of various salts, CaCl2 and KCl have the highest and lowest effect on the CO2 diffusion coefficient, respectively. Finally, a set of direct numerical simulations were conducted to study the impact of CO2 diffusion coefficient on CO2 dissolution process. The results obtained from this research work shed light on the importance of CO2 diffusion coefficient changes in saline water for prediction of dissolution process behavior.