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Abstract Salt caverns are widely regarded as a suitable option for the underground storage of hydrogen. However, an accurate assessment of the hydrogen leakage through the walls of salt caverns into the surrounding formations remains crucial. In this work, the flow of hydrogen into the surrounding formation is evaluated by assuming that salt rock consists of bundles of tortuous nano-capillary tubes. A formulation was then proposed to model the flow in linear and radial domains. The formulations are based on a newly proposed unified gas flow model that is valid for the entire range of Knudsen numbers and accounts for gas slippage, bulk diffusion, and Knudsen diffusion. A finite-difference approximation with an iterative procedure was then used to treat the nonlinearity and solve the presented formulations. The formulations were validated against the experimental data reported in the literature. The results obtained indicated that for hydrogen flow over a wide range of pore radii and operating pressures and temperatures, the slippage flow regime must be considered. In a salt cavern with relevant dimensions and operating conditions, the cumulative hydrogen leakage after 30 years of cyclic storage was only 0.36% of the maximum storage capacity. It was also noticed that most of the leaked hydrogen would flow back into the salt cavern at times when the pressure in the salt cavern is lower than the surrounding pressure, e.g. during production and subsequent idle times. At low storage pressure and very tight salt rock, diffusion was the most important mechanism for hydrogen transport. At a high pressure though, viscous flow became the predominant leakage mechanism. The presence of a thin interlayer such as mudstone, carbonate, and anhydrite in the body of the salt rock can have a significant impact on the amount of leakage. It appeared that although increasing the maximum operating pressure from 120 to 135 bar only led to an 11.9% increase in the maximum storage capacity, the hydrogen loss increased significantly from 0.007% at 120 bar to 0.36% at 135 bar. Furthermore, although the absolute leakage rate for natural gas storage was higher than that for hydrogen storage, the relative leakage rate in relation to the maximum salt cavern capacity was much lower. The leakage range was also lower for natural gas storage compared to hydrogen storage. The formulations presented and the results obtained in this study can help to have a better understanding of the salt caverns when it comes to large-scale hydrogen storage.

Drilling through active shale formations has been a challenging practice in the oil and gas industry for a long period of time, given the complexity of shale structure and its interaction with Water Based Muds (WBMs). Although there have been many additives and methodologies proposed for a safe drilling through shale formations using WBMs, little success has been reported to the application of these methods once tested under different field conditions. In this paper, a new WBM formulated by nanomaterials was proposed to stabilize active shale layers during drilling. A series of rheological, density, filtration loss, bentonite dispersion and shale recovery tests were conducted on the mud samples formulated by nanosilica and Nano Glass Flakes (NGFs). The results indicated that NGF, as a cheap but effective nanomaterial, is able to significantly reduce the flirtation loss without posing any significant impacts on the density and the rheology of WBMs. It also appeared that the bentonite molecules were incapable to either hydrate or disperse in the drilling fluid system in the presence of NGFs. It seems that NGFs can stabilize clay minerals and reduce the filtration loss as remarkably efficient additive, but caution must be taken to ensure that they are properly disperse in the WBMs.

The heavy oil reservoirs are currently mainly targeted by thermal enhanced oil recovery technologies, particularly, steam flooding. Steam flooding is carried out by introducing heat into the reservoir to unlock the recovery of heavy oil by reducing oil viscosity. Several investigations were carried out to improve oil recovery by steam flooding. Most recently, high steam flooding is reported as an effective approach to improve recovery in high pressure heavy oil reservoirs. The oil recovery from steam flooding is substantially affected by the steam quality and injection temperature. In this study, an attempt was made to look into the integration of parameters, i.e. steam quality and injection temperature upon steam flooding on oil recovery by using a simulation approach via ECLIPSE. The results obtained indicated that high temperature along with the moderate value of steam quality gives the best result regarding oil recovery for steam flooding in an economical way.

It is essential to characterize fluid flow in porous media to have a better understanding of petrophysical properties. Many approaches were developed to determine reservoir permeability among which the integrated analysis of hydraulic flow unit (HFU) and electrofacies (EF) is considered to be useful one. However, the application of HFU and EF analysis has not been totally understood with a limited data to develop correlation for less distance offset wells. In this study, an attempt was made to show the application of integrating HFU and EF for reliable estimation of permeability using core and wireline log data in one of the gas fields in Pakistan. The results obtained indicate that the integrated approach proposed in this study can be used, especially in less distance offset wells when a limited number of data are available for petrophysical characterization.

Many parameters have been indicated crucial for the selection of a saline aquifer as a carbon dioxide (CO2) storage site. However, less attention has been given to the impact of heterogeneity on the performance of these storage media. Thus, the heterogeneity effect was evaluated in this paper by adopting a numerical modeling approach and the existing screening criterion developed for the aquifers was updated. The updated criterion for CO2 storage purpose would enhance the confidence level during the selection of deep saline aquifer and thus, help to address the climate change issue. The numerical modeling was carried out via CO2STORE module of Eclipse300 Simulator to evaluate the effect of different levels of heterogeneity on CO2 storage potential. Different degrees of heterogeneity from homogenous systems to highly heterogeneous systems in the model were incorporated through the Lorenz coefficient. In this way, simulation of nine cases was carried out for three different aquifers with different porosity values. A comparison of these results showed that heterogeneity causes the aquifer to have lower storage capacity. On the trapping potential, dissolution trapping was significant and the amount of free gas in all cases was minimum. In addition, the aquifer with the highest level of heterogeneity (HLH) had a minimum fraction of residual trapping regardless of porosity. It was also found that final pressure at the end of 30 years is the same and high for low-level heterogeneity (LLH) and medium level heterogeneity (MLH) cases and low for HLH, while the injection rate stability duration is least for HLH and maximum for LLH. Based on the results obtained, it can be concluded that low to medium level heterogeneous aquifers with a good porosity can be a suitable choice for CO2 storage.

Abstract Miscible CO2-based enhanced oil recovery (CO2-EOR) flooding has been used, on many occasions, to maximize the recovery by mobilizing the residual oil. The success of this method, however, depends highly on the minimum miscibility pressure (MMP), the compatibility of CO2 with the reservoir rock and fluids. Although there have been several studies on the application of CO2-EOR, the impact of oil compositions associated with MMP on the feasibility of this technique has not been addressed elsewhere. In this study, a simulation study was carried out to investigate the effect of three different oil compositions on the miscibility and ultimate oil recovery of miscible CO2-EOR method. The results obtained indicated the oil type does not pose a significant impact on the success of miscible CO2-EOR. It was also found that the ultimate recovery of oil increases in a short period of time by injecting CO2 at the miscible conditions at the early stage of natural production. Comparatively, the reservoir with the fluid sample S2 seems to be a suitable choice for the miscible CO2 flooding once the recovery factor was considered together with the total amount of the fluid injected and produced.

Abstract Reservoir characterization carried out for the quantitative representation of a reservoir leads to effectively managing the hydrocarbon reservoir. There have been few attempts made to characterize the reservoir and assess the potential of a reservoir for the sweet spots using seismic, geomechanical, and petrophysical characteristics where a combination of seismic and petrophysical characters is often ignored given the complexity of such integration. To the best of our knowledge, none of the studies have provided overall reservoir characterization workflows using the combination of petrophysical and geomechanical attributes for sweet spot detection. This study aims to adopt a new color transformation overlay scheme to assess the potential of reservoirs by identifying the sweet spots that can guide to propose a location for a new well. The core scale measurements and well log interpretation were used to determine the petrophysical and geomechanical properties of a highly complex sandstone reservoir which were used as the input to build a 3D reservoir model. The results obtained indicated that predicting the distribution of sweet spots is an effective scheme for well-planning and field development in the region. Four sweet spots are identified in the studied reservoir based on the color transformation overlay approach which has heterogeneous continuity behavior in vertical and horizontal directions. The identification of sweet spots based on top view is not enough for the complete understanding of spreading in all directions. Cross-sectional analysis of the color transformation overlay model revealed that there is a sweet spot near Well-E in west which has ideal reservoir potential and place to consider another proposed well.

Cyclic steam stimulation (CSS) is widely used for production from heavy oil reservoirs where oil viscosity is manipulated by heat. Many analytical models have been developed to predict the temperature evolution in the reservoir and estimate the oil recovery. However, they often suffer from a number of assumptions which ultimately reduce their efficiency in providing a realistic prediction. In this study, a numerical solution was proposed for two-dimensional heat conduction in heavy oil reservoirs to obtain the temperature evolution during the soaking period. For a better comparison, an industry widely accepted analytical model, knows as the Boberg and Lantz steam stimulation model, together with its modified version later proposed by Bensten and Donohue were considered to examine temperature changes in a synthetic case study. The results obtained indicated that the analytical solutions overestimate the average temperature of the reservoir by 42% after 300 days of injection while the numerical formulation can provide a close prediction. This numerical approach could be a useful tool to estimate the temperature and oil production from heavy oil reservoirs. Keywords: Thermal EOR, Steam stimulation, Finite element, Boberg and Lantz model, Temperature prediction

There have been many attempts to improve the filtration control of water based muds under High Pressure High Temperature (HPHT) condition using a cost effective approach. Nano particles are perhaps the best option considering their successful applications reported in many studies. However, they are often expensive and pose unfavourably changes on the rheology of the muds. In this paper, an attempt was made to show the application of Nano Glass Flakes (NGFs) as a cheap but effective nano particle to control the filtration of water based muds under HPHT conditions. Performing a series of rheology, filtration and conductivity tests on the mud samples with unmodified NGFs revealed that this nano particle increases the mud rheology, yield point and gel strength of the mud with a slight impact on the filtration loss. However, by modifying the surface charges of NGFs with a cationic surfactant, filtration loss was significantly reduced without any severe impacts on the mud rheology. Considering the conductivity of the mud which increases by adding the modified NGF, this nano particle might be a good choice to improve the overall performance of water based muds under HPHT conditions. Keywords: Nano glass flakes, Filtration loss, Rheology, HPHT, Dispersion

Excessive emission of greenhouse gases into the atmosphere has resulted in a progressive climate change and global warming in the past decades. There have been many approaches developed to reduce the emission of Carbon Dioxide (CO2) into the atmosphere, among which Carbon Capture and Storage (CCS) techniques has been recognized as the most promising method. This paper provides a deeper insight about the CCS technology where CO2 is captured and stored in deep geological formations for stabilization of the earth's temperature. Principles of capturing and storage for a long-term sequestration are also discussed together with the processes, mechanisms and interactions induced by supercritical CO2 upon injection into subsurface geological sites. Keywords: CCS technologies, CO2 capture, CO2 transportation, CO2 storage, Leakage, Costs

Abstract Flow experiments have been conducted for two-phase flow in a vertical pipe. The experiments were made for highly viscous oil–water in a stainless pipe at 250 psig pressure through the laboratory-scale flow test equipment. The test section used is a vertical transparent tube of 50 cm length and 40 mm ID. The test fluid utilized in this experiments is synthetic oil (viscosity = 35 mPas, density = 860 kg/m3) and filtered tap water (interfacial tension 31 mN/m at 20 °C, viscosity 0.95 mPas at 25 °C). The measurements of superficial velocities of oil and water were varied between 0.01 to 3 m/s. According to the experimental observations using audiovisual recordings, a flow pattern map was identified at different condition. Measuring the variations in pressure gradient and flow patterns at different superficial velocities of two-phase flow, six typical flow patterns were categorized and mapped under two groups, oil-dominant region and water-dominant region, and categorized based on the variations of oil and water superficial velocities, and mixture fluid velocity, at different amount of the water holdup in the vertical tubing. The measurements of the total pressure gradient at five different mixture fluid velocities were conducted verses water holdup in vertical tubing. The results show that all the upward flows show an identical flow pattern, where the pressure gradients increase with increasing mixture fluid velocity and water cut with similar trend. The experiments show a clear peak in the pressure gradient as a result of the frictional factor, specifically at the point of flow patterns occurs (i.e., water holdup ~ 30%). The results concluded that the pressure gradient is significantly influenced by flow patterns and flow rates. Besides, the oil viscosity has a high effect on the pressure gradients; however, it is observed that at similar water and oil superficial velocities, there is a subsequent increase in the pressure gradient due to the increase in oil viscosity.

Accurately measuring wettability is of the utmost importance because it influences several reservoir parameters while also impacting reservoir potential, recovery, development, and management plan. As such, this study proposes a new formulated mathematical model based on the correlation between the Amott-USBM wettability measurement and field NMR T2LM log. The exponential relationship based on the existence of immiscible fluids in the pore space had a correlation coefficient of 0.95. Earlier studies on laboratory core wettability measurements using T2 distribution as a function of increasing water saturation were modified to include T2LM field data. Based on the trends observed, water-wet and oil-wet conditions were qualitatively identified. Using the mean T2LM for the intervals of interest and the formulated mathematical formula, the various wetting conditions in existence were quantitatively measured. Results of this agreed with the various core wettability measurements used to develop the mathematical equation. The results expressed the validity of the mathematical equation to characterise wettability at the field scale. With the cost of running NMR logs not favourable, and hence not always run, a deep ensemble super learner was employed to establish a relationship between NMR T2LM and wireline logs. This model is based on the architecture of a deep learning model and the theoretical background of ensemble models due to their reported superiority. The super learner was developed using nine ensemble models as base learners. The performance of nine ensemble models was compared to the deep ensemble super learner. Based on the RMSE, R2, MAE, MAPD and MPD the deep ensemble super learner greatly outperformed the base learners. This indicates that the deep ensemble super learner can be used to predict NMR T2LM in the field. By applying the methodology and mathematical formula proposed in this study, the wettability of reservoirs can be accurately characterised as illustrated in the field deployment.

Data presented in this article focused on the application of Methyl Ester Sulphonate (MES) surfactant and nanopolystyrene in water based drilling fluid. Data from rheology study using Bingham and Power law models showed that the synergy of MES and nanopolystyrene improved the formulated drilling fluid. Filtration study under LPLT and HPHT conditions showed that MES and nanopolystyrene drilling fluid reduced filtration loss by 50.7% at LPLT and 61.1% at HPHT conditions. These filtration data were validated by filter cake permeability and scanning electron microscope images. Keywords: Methyl Ester Sulphonate, Nanopolystyrene, Rheology, Fluid loss, Drilling fluid

Abstract The main objectives of this study are analysis of spatial behavior of the porosity and permeability, presenting direction of anisotropy for each variable and describing variation of these parameters in Shurijeh B gas reservoir in Khangiran gas field. Porosity well log data of 32 wells are available for performing this geostatistical analysis. A univariate statistical analysis is done on both porosity and permeability to provide a framework for geostatistical analysis and modeling. For spatial analysis of these parameters, the experimental semivariogram of each variable in different direction as well as their variogram map plotted to find out the direction of anisotropy and their geostatistical parameters such as range, sill, and nugget effect for later geostatistical work and finally for geostatistical modeling, two approaches kriging and Sequential Gaussian Simulation are used to get porosity and permeability maps through the entire reservoir. All of statistical and geostatistical analysis has been done using GSLIB and PETREL software. Maximum and minimum direction of continuity are found to be N75W and N15E, respectively. Geostatistical parameters of calculated semivariogram in this direction like range of 7000 m and nugget of 0.2 are used for modeling. Both kriging and SGS method used for modeling but kriging tends to smooth out estimates but on the other hand SGS method tends to show up details. Cross-validation also used to validate the generated modeling.

There have been interests to link different cuttings/cavings to various wellbore failure types during drilling. This concept is essential when caliper and image logs are not available. Identification of wellbore failure during drilling gives more chance of immediate actions before wireline logging program. In this paper, an approach was presented based on the image processing of ditch cuttings. This approach uses the sphericity and roundness of cuttings as input data to classify caving types and subsequently determine the dominant failure type. Likewise, common definitions of cavings were discussed initially before a new criterion is suggested. This quantitative criterion was examined by observations from caliper and acoustic image logs as well. The proposed approach and criterion were implemented on ditch cuttings taken from a well in Western Australia. Results indicate that the primary failure is shear failure (breakout) due to high levels of angular cavings. However, another failure due to the fluid invasion into pre-existing fractures was also recorded by blocky cavings. Keywords: Caving shape, Cuttings, Drilling, Image analysis, Wellbore failures, Roundness, Sphericity

Attempts to reduce the amount of greenhouse gases released into the atmosphere in recent years have led to the development of Carbon Capture and Sequestration (CCS) technology. However, there have been many studies reporting leakages form CO2 storage sites as a result of cement degradation induced by generation of an acidic environment in the storage site. Although there are a number of approaches proposed to enhance the efficiency of the cement, the degradation issue has not been totally resolved yet perhaps due to the excessive corrosives nature of carbonic acid and supercritical CO2. The aim of this study is to propose a methodology to improve the physical and mechanical characteristics of the cement by nanomodification such that a consistent rheology, constant density and a good strength development can be achieved. A new dispersion technique was proposed to ensure that the cement formulation gives a consistent result. The results obtained indicated that unlike the literature mixing, cement slurries prepared by the new mixing technique are very consistent in their rheology, regardless of the sonication parameters chosen. The measurements of the compressive strength performed at the reservoir condition revealed that nanosilica contributes in the strength development up to a certain point. Thermogravimetric Analysis (TGA) conducted at the last stage indicated that the amount of Portlandite left in the cement by adding nanosilica is decreased due to the pozzolanic reaction, which would help the cement to have a higher chance of survival in a storage site. However, cautions must be taken to maintain a certain amount of Portlandite in the cement for slowing down the carbonation rate, as otherwise the matrix of the cement is attacked directly and the cement will be degraded very fast. Keywords: Nanosilica, Dispersion method, Class G cement, Rheology, Compressive strength

Abstract Miscible carbon dioxide (CO2) flooding has been recognized as a promising approach to enhance the recovery of oil reservoirs. However, depending on the injection strategy and rock/fluid characteristics, efficiency of the miscible CO2 flooding varies from reservoir to reservoir. Although, many studies have been carried out to evaluate the performance of the miscible CO2 flooding, a specific strategy which can be strictly followed for a hydrocarbon reservoir has not been established yet. The aim of this study is to assess one of Pakistan’s oil reservoirs for miscible CO2 flooding by applying a modified screening criterion and numerical modeling. As such, the most recent miscible CO2 screening criteria were modified, and a numerical modeling was applied on the prospective reservoir. Based on the results obtained, South oil reservoir (S3) is chosen for a detailed assessment of miscible CO2 flooding. It was also found that implementation of CO2 water-alternating gas (CO2-WAG) injection at early stages of production can increase the production life of the reservoir.

Abstract Carbon capture and sequestration (CCS) has been employed to reduce global warming, which is one of the critical environmental issues gained the attention of scientific and industrial communities worldwide. Once implemented successfully, CCS can store at least 5 billion tons of CO2 per year as an effective and technologically safe method. However, there have been a few issues raised in recent years, indicating the potential leakages paths created during and after injection. One of the major issues might be the chemical interaction of supercritical CO2 with the cement, which may lead to the partial or total loss of the cement sheath. There have been many approaches presented to improve the physical and mechanical properties of the cement against CO2 attack such as changing the water-to-cement ratio, employing pozzolanic materials, and considering non-Portland cements. However, a limited success has been reported to the application of these approaches once implemented in a real-field condition. To date, only a few studies reported the application of nanoparticles as sophisticated additives which can reinforce oil well cements. This paper provides a review on the possible application of nanomaterials in the cement industry where physical and mechanical characteristics of the cement can be modified to have a better resistance against corrosive environments such as CO2 storage sites. The results obtained indicated that adding 0.5 wt% of Carbon NanoTubes (CNTs) and NanoGlass Flakes (NGFs) can reinforce the thermal stability and coating characteristics of the cement which are required to increase the chance of survival in a CO2 sequestrated site. Nanosilica can also be a good choice and added to the cement by as much as 3.0 wt% to improve pozzolanic reactivity and thermal stability as per the reports of recent studies.

Depleted gas reservoirs are recognized as the most promising candidate for carbon dioxide storage. Primary gas production followed by injection of carbon dioxide after depletion is the strategy adopted for secondary gas recovery and storage practices. This strategy, however, depends on the injection strategy, reservoir characteristics and operational parameters. There have been many studies to-date discussing critical factors influencing the storage performance in depleted gas reservoirs while little attention was given to the effect of residual gas. In this paper, an attempt was made to highlight the importance of residual gas on the capacity, injectivity, reservoir pressurization, and trapping mechanisms of storage sites through the use of numerical simulation. The results obtained indicated that the storage performance is proportionally linked to the amount of residual gas in the medium and reservoirs with low residual fluids are a better choice for storage purposes. Therefore, it would be wise to perform the secondary recovery before storage in order to have the least amount of residual gas in the medium. Although the results of this study are useful to screen depleted gas reservoirs for the storage purpose, more studies are required to confirm the finding presented in this paper.

Depleted gas reservoirs are used for a large-scale carbon dioxide (CO2) storage and reduction of the greenhouse gas released into the atmosphere. To identify a suitable depleted reservoir, it is essential to do a preliminary and comprehensive assessment of key storage factors such as storage capacity, injectivity, trapping mechanisms, and containment. However, there are a limited number of studies providing a preliminary assessment of CO2 injectivity potential in depleted gas reservoirs prior to a CO2 storage operation. The aim of this study is to provide a preliminary assessment of a gas field located in Malaysia for its storage potential based on subsurface characterization prior to injection. Evaluation of the reservoir interval based on the facies, cores, and wireline log data of a well located in the field indicated that the pore type and fabrics analysis is very beneficial to identify suitable locations for a successful storage practice. Although the results obtained are promising, it is recommended to combine this preliminary assessment with the fluid-mineral interactions analysis before making any judgment about reliability of storage sites.

Carbon capture and sequestration technology is recognized as a successful approach taken to mitigate the amount of greenhouse gases released into the atmosphere. However, having a successful storage practice requires wise selection of suitable wells in depleted oil or gas fields to reduce the risk of leakage and contamination of subsurface resources. The aim of this paper is to present a guideline which can be followed to provide a better understanding of sophisticated wells chosen for injection and storage practices. Reviewing recent studies carried out on different aspects of geosequestration indicated that the fracture pressure of seals and borehole conditions such as cement-sheath integrity, distance from faults and fractures together with the depth of wells are important parameters, which should be part of the analysis for well selection in depleted reservoirs. A workflow was then designed covering these aspects and it was applied to a depleted gas field in Malaysia. The results obtained indicated that Well B in the field may have the potential of being a suitable conduit for injection. Although more studies are required to consider other aspects of well selections, it is recommended to employ the formation integrity analysis as part of the caprock assessment before making any decisions.

Sand production is an undesired phenomenon occurring in unconsolidated formations due to shear failure and hydrodynamic forces. There have been many approaches developed to predict sand production and prevent it by changing drilling or production strategies. However, assumptions involved in these approaches have limited their applications to very specific scenarios. In this paper, an elliptical model based on the borehole shape is presented to predict the volume of sand produced during the drilling and depletion stages of oil and gas reservoirs. A shape factor parameter is introduced to estimate the changes in the geometry of the borehole as a result of shear failure. A carbonate reservoir from the south of Iran with a solid production history is used to show the application of the developed methodology. Deriving mathematical equations for determination of the shape factor based on different failure criteria indicate that the effect of the intermediate principal stress should be taken into account to achieve an accurate result. However, it should be noticed that the methodology presented can only be used when geomechanical parameters are accurately estimated prior to the production stage when using wells and field data.

Carbon capture and storage (CCS) is a developed technology to minimize CO2 emissions and reduce global climate change. Currently, shale gas formations are considered as a suitable target for CO2 sequestration projects predominantly due to their wide availability. Compared to conventional geological formations including saline aquifers and coal seams, depleted shale formations provide larger storage potential due to the high adsorption capacity of CO2 compared to methane in the shale formation. However, the injected CO2 causes possible geochemical interactions with the shale formation during storage applications and CO2 enhanced shale gas recovery (ESGR) processes. The CO2/shale interaction is a key factor for the efficiency of CO2 storage in shale formations, as it can significantly alter the shale properties. The formation of carbonic acid from CO2 dissolution is the main cause for the alterations in the physical, chemical and mechanical properties of the shale, which in return affects the storage capacity, pore properties, and fluid transport. Therefore, in this paper, the effect of CO2 exposure on shale properties is comprehensively reviewed, to gain an in-depth understanding of the impact of CO2/shale interaction on shale properties. This paper reviews the current knowledge of the CO2/shale interactions and describes the results achieved to date. The pore structure is one of the most affected properties by CO2/shale interactions; several scholars indicated that the differences in mineral composition for shales would result in wide variations in pore structure system. A noticeable reduction in specific surface area of shales was observed after CO2 treatment, which in the long-term could decrease CO2 adsorption capacity, affecting the CO2 storage efficiency. Other factors including shale sedimentary, pressure and temperature can also alter the pore system and decrease the shale “caprock” seal efficiency. Similarly, the alteration in shales’ surface chemistry and functional species after CO2 treatment may increase the adsorption capacity of CO2, impacting the overall storage potential in shales. Furthermore, the injection of CO2 into shales may also influence the wetting behavior. Surface wettability is mainly affected by the presented minerals in shale, and less affected by brine salinity, temperature, organic content, and thermal maturity. Mainly, shales have strong water-wetting behavior in the presence of hydrocarbons, however, the alteration in shale’s wettability towards CO2-wet will significantly minimize CO2 storage capacities, and affect the sealing efficiency of caprock. The CO2/shale interactions were also found to cause noticeable degradation in shales’ mechanical properties. CO2 injection can weaken shale, decrease its brittleness and increases its plasticity and toughness. Various reductions in tri-axial compressive strength, tensile strength, and the elastic modulus of shales were observed after CO2 injection, due to the dissolution effect and adsorption strain within the pores. Based on this review, we conclude that CO2/shale interaction is a significant factor for the efficiency of CCS. However, due to the heterogeneity of shales, further studies are needed to include various shale formations and identify how different shales’ mineralogy could affect the CO2 storage capacity in the long-term.

In the original publication, third author name was incorrectly published as Meftah Hairir.