CO2 Injection In Saline Aquifers Research Articles

Optimal monitoring design for uncertainty quantification during geologic CO[formula omitted] sequestration: A machine learning approach

An effective monitoring design is crucial to ensure the safe and permanent geologic storage of CO2. Optimal monitoring design involve an optimal placement of monitoring wells, and optimal monitoring measurement data (pressure, CO2 saturation, temperature, etc.). We developed a filtering-based data assimilation approach to design an optimal monitoring strategy for well placement and monitoring data design. To efficiently solve the optimization problem and reduce computational costs, Artificial Neural Networks are used to develop computationally efficient reduced-order models based on full-physics numerical simulations of CO2 injection in saline aquifers. We demonstrate our approach in two scenarios of CO2 leakage through legacy or abandoned wellbores where an optimal monitoring strategy are devised to reduce the uncertainty in cumulative CO2 leakage in the geologic CO2 sequestration (GCS) site. The optimal monitoring design resulted in an uncertainty reduction in the cumulative leakage of CO2 of approximately 73% and 62% in each case, respectively. The proposed approach is efficient in developing monitoring designs under geologic uncertainty and enables safe geologic carbon sequestration operations.

Modeling Self-Sealing Mechanisms in Fractured Carbonates Induced by CO2 Injection in Saline Aquifers.

In the future, there will be competition among natural gas, CO2, and hydrogen for suitable geological storage sites. Therefore, it is crucial to evaluate all of the potential storage options. One promising option is the utilization of fractured carbonate rocks, which offer significant opportunities for gas sequestration in depleted reservoirs and saline aquifers. The objective of this study is to assess the feasibility of using carbonate matrix rocks in saline aquifers for carbon capture and storage (CCS) projects. Although carbonate reservoirs are currently not ranked highly for carbon storage due to the risk of CO2 leakage, their matrix rock with reactive minerals like calcite and dolomite, along with the possibility of natural fractures, presents an interesting opportunity. This research proposes a reassessment of the role of fractures, which are typically viewed as a risk factor, within a novel and integrated context. It combines geochemical modeling with numerical models that incorporate two distinct density levels of natural fractures. The interactions between the carbonate matrix, the formation brine, and the injected CO2 can lead to water vaporization and the deposition of evaporite minerals, known as the halite scale, within the porous medium. These minerals can be transported within highly conductive fractures that possess a permeability 100 times greater than the matrix. The study findings indicate that the fractures become filled, creating a natural seal that prevents CO2 leakage through what was previously considered a potential pathway in both models and different initial pH values. Furthermore, the results demonstrate the formation of secondary minerals through the reaction of CO2 and its aqueous counterparts with rock matrix minerals. These minerals, including Dawsonite, are then deposited within fracture apertures, compensating for the dissolution of calcite from the matrix and reducing the risk of enhanced fracture conductivity during CCS operations. The deposition of halite scales in initially acidic-brine saturated aquifers and/or Dawsonite scales in initially alkaline-brine saturated aquifers serves to partially counterbalance the permeability enhancement resulting from calcite dissolution. This phenomenon makes carbonate rocks a more secure option and highlights their potential suitability for CCS projects. The existence of these scales acts as a protective barrier, reducing the risk of increased permeability and enhancing the integrity of the storage reservoir.

Transient Pressure Interference during CO2 Injection in Saline Aquifers

Summary CO2 injection in subsurface geological formations (e.g., deep saline aquifers) causes pressure perturbations over a large area surrounding the injection well. Observation wells are widely considered in geologic CO2 storage (GCS) projects where the pressure perturbation induced by CO2 injection is measured. In this work, we use analytical and numerical modeling tools along with field data to examine the pressure behavior in GCS projects before and after CO2 arrival at an observation well. Before CO2 arrival, a baseline pressure trend is established which corresponds to single-phase brine flow across the observation well (approximated by the Theis solution). Therefore, analysis of early time pressure data is straightforward, provides the single-phase flow characteristics (mobility and storativity), and helps in establishing a baseline pressure change that can be extended beyond the single-phase flow period at the observation well. Upon CO2 arrival, a departure from this baseline trend is expected. For the pressure to detect the CO2 arrival at an observation well, the departure from baseline pressure behavior must be significant and well above the background noise levels. We use existing analytical models to determine the strength of the expected pressure departure signal from the baseline trend upon CO2 arrival. The strength of the expected pressure departure is found to be directly proportional to the change in the mobility upon CO2 arrival. Larger change in the flow mobility—compared with single-phase brine mobility—results in a stronger pressure departure signal. In addition, the departure is found to be upward (downward) from the baseline pressure trend when the mobility ratio is less (more) than unity. We present a pressure analysis approach through application to synthetic and field data and show the characteristic pressure behavior before and after CO2 arrival. We show that while generally the pressure can be either above or below the expected baseline pressure trend, it would be likely above the baseline upon CO2 arrival. This is because the mobility ratio becomes less than unity after CO2 arrival. We show that depending on the reservoir characteristics, changes in the pressure trend may or may not be sufficient to detect the CO2 arrival.

Pressure falloff testing to characterize CO2 plume and dry-out zone during CO2 injection in saline aquifers

The fluid mobilities and the lateral extent of the CO2 plume and the dry-out zone are among important unknowns required to effectively manage CO2 storage in saline aquifers projects. These unknowns can be derived from pressure falloff testing which has been widely used to characterize the subsurface. This work provides a three-region analytical solution for falloff pressure during the infinite-acting period of CO2 injection in saline aquifers. The solution is derived using Laplace transformation technique of the governing diffusivity equations and the accompanying initial and boundary conditions. The exact solution is validated against numerical results obtained from a black-oil reservoir simulator for two cases. The solution is approximated into simple forms in real-time domain considering different time periods. Then, a graphical semi-log analysis technique based on the approximate solutions is provided as an interpretation tool of falloff tests where the fluid mobilities and the extents of dry-out zone and CO2 plume can be inferred. The interpretation technique is applied to synthetic falloff test data to investigate its potential and reliability.

Characterization and monitoring of reservoir flow barriers from pressure transient analysis for CO2 injection in saline aquifers

Understanding of flow barriers in a saline aquifer evaluated for geological storage of carbon dioxide is the key point for decision making and designing injection operations. The barriers may significantly limit injection capacity, while their dynamic behavior during the operational phase, like fault reactivation and leakage out of the target formation, may cause unexpected completion of injection phase and have negative environmental consequences. The pressure data obtained in real-time during well testing and main phase of injection with installation of Permanent Downhole Gauges (PDG) may be utilized to characterize and monitor reservoir boundary conditions. Here, Pressure Transient Analysis (PTA) can be employed as interpretation tool.In this work, the case of faults acting as flow barriers including scenarios of sealing and leaking faults is studied using the history of CO2 injection into the Tubåen formation of the Snøhvit field as testing data set. The paper starts from answering general questions on applicability of PTA for CO2 injection, related to capabilities and limitations of single-phase flow models. It continues with suggesting and testing approximate approaches to improve the capabilities of such models to deal with CO2 injection cases (brine replica). Finally, an integrated workflow (or a technology, if combined with well surveillance system) for characterizing and monitoring flow barriers in geological storage projects is suggested. This workflow uses advantages of the models above for real-time data analysis. The paper concludes with recommendations for pre-injection well testing and surveillance during main injection phase, closing the loop with application guidelines.

Thermo-Fluid-Dynamical Modelling of Salt Precipitation During Co2 Injection in Saline Aquifers, and the Effect on Injectivity

Thermo-Fluid-Dynamical Modelling of Salt Precipitation During Co2 Injection in Saline Aquifers, and the Effect on Injectivity

CO2 Storage with Mobility Control

The high mobility contrast between injected CO2 and the formation brine at reservoir conditions makes the displacement efficiency low and can give early breakthrough of injected CO2 into brine extraction wells for pressure management, or early reaching of spill points in structural traps. The storage capacity could in many cases be increased if efficient mobility control methods could be implemented for the injected CO2. In this paper we investigate the potential benefits of mobility control for CO2 injection in saline aquifers using both a commercial reservoir simulator and a specially developed module for the Matlab Reservoir Simulation Toolbox. The mobility control method investigated is surfactants for foam generation. These exists today both as water soluble and CO2 soluble surfactants, and the efficiency of both types are studied. Rough estimates of the cost of additional storage capacity are made. Results show that the storage capacity in some cases can be more than doubled, at a cost the order of 7 $ per additional tonne of stored CO2.

Geologic CO2 sequestration monitoring design: A machine learning and uncertainty quantification based approach

Monitoring is a crucial aspect of geologic carbon dioxide (CO2) sequestration risk management. Effective monitoring is critical to ensure CO2 is safely and permanently stored throughout the life-cycle of a geologic CO2 sequestration project. Effective monitoring involves deciding: (i) where is the optimal location to place the monitoring well(s), and (ii) what type of data (pressure, temperature, CO2 saturation, etc.) should be measured taking into consideration the uncertainties at geologic sequestration sites. We have developed a filtering-based data assimilation procedure to design effective monitoring approaches. To reduce the computational cost of the filtering-based data assimilation process, a machine-learning algorithm: Multivariate Adaptive Regression Splines is used to derive computationally efficient reduced order models from results of full-physics numerical simulations of CO2 injection in saline aquifer and subsequent multi-phase fluid flow. We use example scenarios of CO2 leakage through legacy wellbore and demonstrate a monitoring strategy can be selected with the aim of reducing uncertainty in metrics related to CO2 leakage. We demonstrate the proposed framework with two synthetic examples: a simple validation case and a more complicated case including multiple monitoring wells. The examples demonstrate that the proposed approach can be effective in developing monitoring approaches that take into consideration uncertainties.

Experimental Study of Density-driven Convection in Porous Media by Using MRI

Density-driven convection is known as one of the physical phenomena for CO2 injection in saline aquifers, which accelerates the transfer of CO2 into the groundwater, increases the dissolution rate and shorten the dissolution time, thus it is favourable for long-term CO2 injection and the practical interest of storage security. Understanding how the occurrence and form of convective fingers is crucial to understanding the role of that Density-driven-convection behaviour. The purpose of this paper is to design a visual experimental set-up based on the MRI technique and present new analogue fluid pairs that reconstructed the convective process. The density-driven convection was formed by two miscible liquids at the interface demonstrated by fingers. We observed the development and growth of density-driven fingers of two-phase fluid i.e., water/ deuterium oxide, and brine/ deuterium oxide at different permeability porous media. Experiments indicated that the relationship of convection onset time to Rayleigh number changed with the density difference and permeability. We present an experimental study for the Rayleigh number in the range 583.279 to 2054.111. The results show that the higher permeability and density difference is conducive to shorten the convection onset time. The motivation behind this results is related to the implications for predicts the CO2 dissolution trapping time and accumulations in geological storage of carbon dioxide.

Geomechanical effects of CO2 storage in depleted gas reservoirs in the Netherlands: Inferences from feasibility studies and comparison with aquifer storage

In this paper, the geomechanical impact of large-scale carbon dioxide (CO2) storage in depleted Dutch gas fields is compared with the impact of CO2 storage in saline aquifers. The geomechanical behaviour of four potential CO2 storage sites is examined using flow and geomechanical simulations. Many gas reservoirs in the Netherlands are found in fault blocks, one to a few kilometres wide, laterally bounded by sealing faults. Aquifer depletion or re-pressurization in the lateral direction is seldom an issue because of a lack of active aquifers. Reservoir pressure changes are therefore limited to a gas-bearing fault block, while the induced stress changes affect the gas reservoir and extend 1–3 km away into the surrounding rock. Arguments in favour of CO2 storage in depleted gas fields are: proven seal quality, availability of field data, no record of seal integrity failure by fault reactivation from the seismically active producing Dutch gas fields, and the potential benefits of restoring the virgin formation pressure and stress state to geomechanical stability. On the other hand, CO2 injection in saline aquifers causes pressure build-up that exceeds the virgin hydrostatic pressure. Stress perturbations resulting from pressure build-up affect large areas, extending tens of kilometres away from the injection wells. Induced stresses in top seals are, however, small and do not exceed a few tenths of megapascal for a pressure build-up of a few megapascals in the storage formation. Geomechanical effects on top seals are weak, but could be enhanced close to the injection zone by the thermal effects of injection. Uncertainties related to characterisation of large areas affected by pressure build-up are significant, and seal quality and continuity are more difficult to be demonstrated for aquifers than for depleted gas reservoirs that have held hydrocarbons for millions of years.

Geochemical modelling of formation damage risk during CO2 injection in saline aquifers

This study provides an understanding of the impact of geochemical reactions during and after CO2 injection into a potential storage site. The results of calculations of geochemical reactivity of reservoir rock and of cap rock during and after CO2 injection were performed using a geochemical simulator, with the calculations showing that for these conditions up to 0.5 mol of CO2 can be dissolved per kg of water. The risk of dissolution of primary cements was considered and identified. In addition, the potential of carbonation reactions to permanently sequester CO2 was considered, although these reactions were shown to be very slow relative to other processes. The implications for security of storage are that while dolomite nodules exist in the sandstone formation, these do not contribute significantly to the overall rock strength, and hence the risk of dissolution of the formation or caprock causing significant leakages pathways is very low. Further calculations were performed using a commercial reservoir simulation code to account for brine evaporation, halite precipitation and capillary pressure re-imbibition. The impact on injectivity was found not to be significant during continuous and sustained injection of CO2 at a constant rate. Capillary pressure effects did cause re-imbibition of saline brine, and hence greater deposition, reducing the absolute porosity by up to 13%. The impact of the halite deposition was to channel the CO2, but for the configuration used there was not a significant change in injection pressure.

An engineering solution for CO2 injection in saline aquifers

In this proposed CO2 injection system, brine is extracted from the target storage aquifer by means of a lateral horizontal completion located near the top of the formation. It should be noted that the brine is not lifted to the surface. An Electrical Submersible Pump (ESP) is used to extract the brine and boost its pressure, before it is mixed with CO2 that is injected down the vertical section of the well. The mixing takes place in the vertical section of the well below the upper lateral. The CO2–brine mix is then injected into the same formation through a lower lateral. A down-hole tool would be used to maximise agitation and contact area between CO2 and brine in the vertical mixing section of the well, which may be tens to hundreds of metres long, depending on the thickness of the formation.The advantages of this method are that there is little overall pressure increase, because CO2 is mixed with brine extracted from the formation, and also the extracted brine is already at high pressure when it is mixed with the CO2, greatly increasing the solubility of CO2 and reducing the volume of brine required. Energy is not expended lifting the brine to surface nor is there any concern about handling large volumes of acidic brine in the surface equipment. In this study, in addition to the concept of the down-hole mixing (DHM) method which is presented, the application of the DHM method in a hypothetical storage site (Lincolnshire—Smith et al., 2012) is also examined. The calculations are performed to identify the optimum rates of water extraction and injection of dissolved CO2 in brine.

CO2 flow in saline aquifer with salt precipitation

Purpose – The purpose of this paper is to introduce the solution to two-phase flow in CO2/brine system with salt precipitation by applying mixed hybrid finite element (MHFE) method to pressure equation and finite volume (FV) method to saturation equation. Mixed finite element method solves pressure and velocity in two subspaces while hybrid method is an extension of mixed method, where the Lagrange multiplier is added to the former in order to ensure the continuity from one element to the adjacent elements. The authors propose the modeling of salt precipitation using core flood experimental result and adapt to be applicable for numerical modeling. Design/methodology/approach – The governing equations are discretized using Mixed Hybrid Finite Element-Finite Volume (MHFE-FV) method. This method has the feature of localized conservation which is attractive for application on heterogeneous porous media. In addition to this, the salt precipitation effect is modeled using the data from core flood experiment (Ott et al., 2011). The random data are linearized to obtain the relationship between salt precipitate and CO2 saturation and implemented to the algorithm for two-phase flow in CO2 and brine system. Findings – The solution of MHFE-FV scheme has good agreement with the solution using implicit pressure and explicit saturation (IMPES) reported by Negara et al. (2011), with average error of 4.20 percent. Localized conservation is demonstrated in the case of randomized heterogeneous porous media where fingering effects are explicitly observed. Salt precipitation prediction using the proposed method is able to predict the decrement of porosity by 16.71 percent and permeability by 22.19 percent. This results in the decreased amount of CO2 injected by 64.70 percent. Research limitations/implications – This paper presents the solution of two-phase flow in CO2 brine system during CO2 injection in saline aquifer using MHFE-FV method with the additional salt precipitation model obtained based on core flood experiment result. Practical implications – A methodology to predict the salt precipitation based on CO2 saturation. Social implications – Contribution to green house gas reduction. Originality/value – The authors use MHFE-FV to solve hyperbolic PDE to obtain accurate results of CO2 saturation, and subsequently use this to compute the salt precipitation.

Modeling techniques to study CO2-injection induced micro-seismicity

CO2 injection in saline aquifers is one solution to avoid the emission of this greenhouse gas to the atmosphere. This process induces a pore-pressure build-up around the borehole that generates tensile and shear micro-earthquakes which emit P and S waves if given pressure thresholds are exceeded. Here, we develop a simple model to simulate micro-seismicity in a layer saturated with brine, based on an analytical solution of pressure diffusion and an emission criterion for P and S waves. The model is based on poroelasticity and allows us to obtain estimations of the hydraulic diffusivity on the basis of the location of the micro-earthquakes (defining the CO2 plume) and the triggering time. Wave propagation of P and S waves is simulated with a full-wave solver, where each emission point is a source proportional to the difference of the pore pressure and the tensile and shear pressure thresholds. Finally a reverse-time migration algorithm is outlined to locate the asynchronous sources induced by the fluid flow, determinated by the maximum amplitude at each cell versus the back propagation time.

Probabilistic cost estimation methods for treatment of water extracted during CO2 storage and EOR

Extraction and treatment of in situ water can minimize risk for large-scale CO2 injection in saline aquifers during carbon capture, utilization, and storage (CCUS), and for enhanced oil recovery (EOR). Additionally, treatment and reuse of oil and gas produced waters for hydraulic fracturing will conserve scarce fresh-water resources. Each treatment step, including transportation and waste disposal, generates economic and engineering challenges and risks; these steps should be factored into a comprehensive assessment. We expand the water treatment model (WTM) coupled within the sequestration system model CO2-PENS and use chemistry data from seawater and proposed injection sites in Wyoming, to demonstrate the relative importance of different water types on costs, including little-studied effects of organic pretreatment and transportation. We compare the WTM with an engineering water treatment model, utilizing energy costs and transportation costs. Specific energy costs for treatment of Madison Formation brackish and saline base cases and for seawater compared closely between the two models, with moderate differences for scenarios incorporating energy recovery. Transportation costs corresponded for all but low flow scenarios (<5000m3/d). Some processes that have high costs (e.g., truck transportation) do not contribute the most variance to overall costs. Other factors, including feed-water temperature and water storage costs, are more significant contributors to variance. These results imply that the WTM can provide good estimates of treatment and related process costs (AACEI equivalent level 5, concept screening, or level 4, study or feasibility), and the complex relationships between processes when extracted waters are evaluated for use during CCUS and EOR site development.

Uncertainty analysis of impact indicators for the integrity of combined caprock during CO2 geosequestration

CO2 capture and geologic sequestration represent one of the most promising options for reducing atmospheric emissions of CO2. Operator choices and subsurface uncertainties each have significant effects on avoiding the risk of triggering fault failure or intact rock failure that could lead to CO2 leakage. With the application of response surface methodology, a Box–Behnken design of experiments was utilized to evaluate the statistical significance of impact indicators, and uncertainty analysis was performed using a robust model to forecast the optimal combination of impact indicators for maintaining caprock integrity during CO2 injection in saline aquifers of the Ordos Basin, China. The Coulomb failure stress and vertical deformation of 130 statistically designed combinations were experimentally determined using numerical simulation. Then, according to the analysis of variance conducted for the response surface quadratic model, the burying depth, friction angle, Young's modulus, Poisson's ratio, and stress field, as well as quadratic terms such as burying depth∗friction angle and Poisson's ratio∗Poisson's ratio, were found to be highly significant with respect to the level of Coulomb failure stress. Among the variables, only burying depth was highly significant with respect to the level of vertical deformation. Furthermore, the results were analyzed and an optimal combination of impact indicators for Coulomb failure stress was determined according to the minimum Coulomb failure stress. The optimum combination had a desirability value of 1.000, which demonstrated the fitness of the selected statistical model in analyzing the experimental data.

A coupling alternative to reactive transport simulations for long-term prediction of chemical reactions in heterogeneous CO&amp;lt;sub&amp;gt;2&amp;lt;/sub&amp;gt; storage systems

Abstract. Fully coupled, multi-phase reactive transport simulations of CO2 storage systems can be approximated by a simplified one-way coupling of hydrodynamics and reactive chemistry. The main characteristics of such systems, and hypotheses underlying the proposed alternative coupling, are (i) that the presence of CO2 is the only driving force for chemical reactions and (ii) that its migration in the reservoir is only marginally affected by immobilisation due to chemical reactions. In the simplified coupling, the exposure time to CO2 of each element of the hydrodynamic grid is estimated by non-reactive simulations and the reaction path of one single batch geochemical model is applied to each grid element during its exposure time. In heterogeneous settings, analytical scaling relationships provide the dependency of velocity and amount of reactions to porosity and gas saturation. The analysis of TOUGHREACT fully coupled reactive transport simulations of CO2 injection in saline aquifer, inspired to the Ketzin pilot site (Germany), both in homogeneous and heterogeneous settings, confirms that the reaction paths predicted by fully coupled simulations in every element of the grid show a high degree of self-similarity. A threshold value for the minimum concentration of dissolved CO2 considered chemically active is shown to mitigate the effects of the discrepancy between dissolved CO2 migration in non-reactive and fully coupled simulations. In real life, the optimal threshold value is unknown and has to be estimated, e.g. by means of 1-D or 2-D simulations, resulting in an uncertainty ultimately due to the process de-coupling. However, such uncertainty is more than acceptable given that the alternative coupling enables using grids of the order of millions of elements, profiting from much better description of heterogeneous reservoirs at a fraction of the calculation time of fully coupled models.

Monitoring above-zone temperature variations associated with CO2 and brine leakage from a storage aquifer

CO2 injection in saline aquifers induces temperature changes owing to processes such as Joule–Thomson cooling, endothermic water vaporization, exothermic CO2 dissolution besides the temperature discrepancy between injected and native fluids. CO2 leaking from the injection zone, in addition to initial temperature contrast due to the geothermal gradient, undergoes similar processes, causing temperature changes in the above zone. Numerical simulation tools were used to evaluate temperature changes associated with CO2 leakage from the storage aquifer to an above-zone monitoring interval and to assess the monitorability of CO2 leakage on the basis of temperature data. The impact of both CO2 and brine leakage on temperature response is considered for three cases (1) a leaky well co-located with the injection well, (2) a leaky well distant from the injector, and (3) a leaky fault. A sensitivity analysis was performed to determine key operational and reservoir parameters that control the temperature signal in the above zone. Throughout the analysis injection-zone parameters remain unchanged. Significant pressure drop upon leakage causes expansion of CO2 associated with Joule–Thomson cooling. However, brine may begin leaking before CO2 breakthrough at the leakage pathway, causing heating in the above zone. Thus, unlike the pressure which increases in response to both CO2 and brine leakage, the temperature signal may differentiate between the leaking fluids. In addition, the strength of the temperature signal correlates with leakage velocity unlike pressure signal whose strength depends on leakage rate. Increasing leakage conduit cross-sectional area increases leakage rate and thus increases pressure change in the above zone. However, it decreases leakage velocity, and therefore, reduces temperature cooling and signal. It is also shown that the leakage-induced temperature change covers a small area around the leakage pathway. Thus, temperature data will be most useful if collected along potential leaky wells and/or wells intersecting potential leaky faults.

Influence of Heterogeneities and Upscaling on CO2 Storage Prediction at Large Scale in Deep Saline Aquifer

What are the effects of spatial variability of permeability on CO2 migration and pressure response to CO2 injection in saline aquifer at industrial scale? Since the extension and intensity of perturbations will be constrained by the geological characteristics of the aquifer, spatial variability will be a key parameter for injectivity and capacity of storage projects. Predictions at regional or basin scale implies the study of geological model of millions grid cells. But for efficient simulations of multiphase flow, the number of grid cells need to be reduced. The purpose of this work is also to evaluate homogenization or simplification methods of permeability field that could be sufficiently accurate for CO2 storage predictions.

Experimental and Numerical Study of the Effects of Halite Scaling on Injectivity and Seal Performance During CO2 Injection in Saline Aquifers

Vaporisation of water during dry CO2 injection can cause salt precipitation and lead to significant reduction in injectivity. Research described in this paper aimed at improving the understanding of the halite scaling process through experimental and numerical investigations. Experimental results indicated porosity reductions of about 3 - 5% and permeability reduction between 13 to 75%. Numerical simulation results have shown that halite scaling can have a significant impact on field operations. They also suggested that, salt precipitation can occur at the caprock interface increasing the sealing capacity around the wellbore.