CO2 Geo-storage Research Articles

Assessing the value of combined use of distributed acoustic sensing (DAS) and multicomponent vertical seismic profiling (VSP) data with network-based full waveform inversion and uncertainty quantification: A case study in Alberta, Canada

Distributed acoustic sensing (DAS) technology, deployed in a vertical seismic profiling (VSP) experimental configuration, has emerged as a candidate for non-disruptive and low-cost seismic monitoring of CO2 geostorage and plume evolution. Full waveform inversion (FWI) has likewise received significant attention because it uses relatively complete physical models of wave propagation and because of its sample-by-sample incorporation of data information. Recent artificial neural network-based FWI algorithms (built with, for instance, recursive neural networks, or RNNs) have added to FWI a range of flexible and efficient tools for gradient computation and options for uncertainty assessment and initial model proxies. An important current research area for the use of DAS data is to better understand how they change our confidence levels in models selected through FWI. In particular, we seek to understand whether either DAS data or conventional geophone data alone are optimal for FWI model selection in the CO2 problem, and if not, to what degree they complement each other. The Snowflake 4D VSP dataset, which includes multi-offset and multi-azimuth broadband sources illuminating both fiberoptic cable and densely sampled accelerometer phones in the borehole, was acquired by our group to directly address these questions. In this study, we quantify uncertainty (UQ) by sampling the posterior model covariance matrix from the inverse Hessian matrix at the end of RNN-FWI runs on the Snowflake baseline data, invoking a velocity-density parameterization, and involving mixtures of accelerometer and DAS data. In this UQ context, the complementary effect of combining accelerometer and DAS data is evident in the Vp and Vs models. Our confidence in the approach is bolstered by its independent prediction of a region of known high uncertainty. In the overall pursuit of reliable and low-cost monitoring tools, this supports continued consideration of a multicomponent sensors supported by DAS approach.

CO2 Geostorage and Enhanced Oil Recovery: Challenges in Controlling Foam/Emulsion Generation and Propagation.

CO2 injection in subterranean reservoirs for storage, oil recovery, or both is challenging because of its very high mobility. Using a CO2 foam or emulsion is a way to remedy this problem by increasing CO2's apparent viscosity. However, the generation of the foam and its propagation in porous media present several issues that have to be overcome for this process to be economically realistic in practice. For example, it may take time, i.e., a number of pore volumes to be injected, before the foam is created. It is the objective of this Article to investigate these issues thoroughly and to identify the mechanisms underlying them by looking at the effects of various parameters. It is found that surfactant adsorption on the surface of the rock is an important factor involved in the delay of foam formation, but this may not explain all of the results. The nature and morphology of the porous medium may be, in some cases, the dominant factors for foam generation and propagation. From an understanding of the origin of the encountered problem, relevant mitigation strategies are envisioned and evaluated. It is found, for example, that when appropriately formulated and injected with the proper process, foam or emulsion generation is strongly accelerated, which very significantly shortens the delay for achieving CO2 storage.

Investigation of the Pore Characteristics and Capillary Forces in Shale before and after Reaction with Supercritical CO2 and Slickwater

CO2–slickwater hybrid fracturing technology is an essential part of shale gas recovery and CO2 geo-storage. However, the exposure to supercritical CO2 (ScCO2) and slickwater can result in potential changes of the pore structures and surface wetting behavior, which affect the gas transportation and CO2 sequestration security in shale reservoirs. Therefore, in this paper, X-ray diffraction (XRD), low-pressure nitrogen gas adsorption (N2GA), mercury intrusion porosimetry (MIP), and fractal analysis were used to describe the pore characteristics of shale before and after ScCO2–slickwater coupling treatments. Shale’s surface wettability was confirmed by contact angle measurements. After the ScCO2–slickwater treatments, the number of micropores (<3.5 nm) and mesopores (3.5–50 nm) increased, while that of macropores (>50 nm) declined based on the N2GA and MIP experiments. Combined with fractal analysis, we argue that the pore connectivity diminished and the pore structure became more complicated. By analyzing the results of XRD, shale pore changes occurring after the ScCO2–slickwater treatment can be explained by the adsorption of polyacrylamide (PAM). Contact angle measurement results showed that the shale’s surface treated by ScCO2 and slickwater was more hydrophilic than that treated by ScCO2 and water, and indirectly prove our argument above. Hence, the coupling using effect of ScCO2 and slickwater can impair the negative effect of CO2 on the shale capillary force to improve shale gas productivity, but it can negatively affect the security of CO2 sequestration in shale reservoirs.

The effect of methylene blue on stearic acid-aged quartz/CO2/brine wettability: Implications for CO2 geo-storage

Carbon dioxide sequestration in geological formations has been proposed as a promising solution to reach net zero carbon emissions but the success of underground CO2 storage in sandstone formations depends on the brine/CO2 wettability of sandstone. Research evidence showed that natural geological formation is hydrophobic even in the presence of minute concentration of inherent organic acids. This study investigates the effect of methylene blue (MB) on CO2 wettability of organic-acid contaminated quartz through the tilted plate contact angle measurement method. Pure quartz substrates were aged in a stearic acid/n-decane solution for one week and subsequently modified with different concentrations of MB (ranging from 10 to 100 mg/L) at a temperature of 60 °C. Advancing (θa) and receding (θr) contact angles were measured under varying conditions of temperature (25 °C and 50 °C), pressure (ranging from 10 to 20 MPa), and salinity (0–0.3 M). The experimental results indicate that pure quartz, when aged in a stearic acid solution, becomes CO2-wet at all temperature, pressure, and salinity conditions. However, at any physio-thermal condition, the wettability of the quartz surfaces was reversed when treated with different concentrations of MB, transitioning to a water-wet state. The findings of this research demonstrate the potential of MB to modify the wetting behaviour of quartz surfaces and enhance CO2 residual trapping in sandstone formations.

The influence of methyl orange on the CO2-brine wettability of organic-acid-aged calcite samples: Implications for CO2 geo-storage

The influence of methyl orange on the CO2-brine wettability of organic-acid-aged calcite samples: Implications for CO2 geo-storage

Optimizing CO2-Water Injection Ratio in Heterogeneous Reservoirs: Implications for CO2 Geo-Storage

The performance of carbon geo-sequestration is influenced by several parameters, such as the heterogeneity of the reservoir, the characteristics of the caprock, the wettability of the rock, and the salinity of the aquifer brine. Although many characteristics, like the formation geology, are fixed and cannot be altered, it is feasible to choose and manipulate other parameters in order to design an optimized storage programme such as the implementation of CO2 injection techniques, including continuous injection or water alternating CO2, which can significantly increase storage capacity and guarantee secure containment. Although WAG (water-alternating-gas) technology has been widely applied in several industrial sectors such as enhanced oil recovery (EOR) and CO2 geo-sequestration, the impact of the CO2-to-water ratio on the performance of CO2 geo-sequestration in heterogeneous formations has not been investigated. In this study, we have constructed a 3D heterogeneous reservoir model to simulate the injection of water alternating gas in deep reservoirs. We have tested several CO2-water ratios, specifically the 2:1, 1:1, and 1:2 ratios. Additionally, we have estimated the capacity of CO2 trapping, as well as the mobility and migration of CO2. Our findings indicate that injecting a low ratio of CO2 to water (specifically 1:2) resulted in a much better performance compared to situations with no water injection and high CO2-water ratios. The residual and solubility trappings were notably increased by 11% and 19%, respectively, but the presence of free mobile CO2 was reduced by 27%. Therefore, in the reservoir under investigation, the lower CO2-water ratio is recommended due to its improvement in CO2 storage capacity and containment security.

Machine learning - based shale wettability prediction: Implications for H2, CH4 and CO2 geo-storage

Shale wettability determines shale gas productivities and gas (H2, CH4 and CO2) geo-storage efficiencies. However, shale wettability is a complex parameter which depends on multiple influencing factors, thus very time-consuming and costly to measure experimentally. Herein, we combined the eXtreme gradient boosting (XGBoost) and Shapley additive explanation (SHAP) machine learning methods to accurately predict brine advancing (θA) and receding (θR) contact angles and estimate shale wettability. The XGBoost model demonstrated much higher prediction accuracies than the commonly-used multiple linear regression and partial least squares regression models, e.g., R2 was 0.946–0.999, 0.794–0.821, and 0.635–0.674, respectively for these three models. The SHAP sensitivity analyses showed that total organic carbon content and gas molecular weight (MG) were the two most significant factors influencing shale wettability. In addition, shale hydrophobicity positively correlated with MG, calcite content, pressure and brine ionic strength, while negatively correlated with temperature and quartz content. This work provides an efficient approach for shale wettability estimation, thus aiding in the implementation of improved gas recovery and gas geo-storage processes, to further guarantee energy security and mitigate climate change.

Investigating the behaviour of NaCl brines and hydrocarbons in porous alumina using low-field NMR relaxation and diffusion methods.

The behaviour of multiple fluid phases within a porous medium is hard to predict. NMR measurements offer an excellent tool to probe such systems in a fast and non-invasive way. Such systems can be relevant to hydrocarbon recovery, catalysis, and CO2 and H2 geo-storage, among others. Since electrolyte solutions are always present in subsurface reservoirs, understanding their behaviour within porous media is highly important. In this study, we use NMR relaxation and diffusion methods to investigate the diffusion coefficients and strength of interactions between alumina surfaces and brines at various NaCl concentrations, focusing on the effect of salt concentration on transport and interactions within the porous structure. Furthermore, we study the spontaneous displacement of dodecane, a model hydrocarbon, from the same alumina pellets using the same brine solutions. Results show that brines of lower salinity consistently displace more dodecane in total, after soaking dodecane-saturated pellets in a brine solution for several days. This indicates that increased salt concentrations can reduce wettability towards the aqueous phase in simple metal oxide surfaces and highlights the capabilities of NMR to efficiently study such systems.

Estimation of CO2-Brine interfacial tension using Machine Learning: Implications for CO2 geo-storage

Carbon capture and storage (CCS) is a promising technique to reduce anthropogenic gases causing climate change. This efficient strategy contributes toward reaching net-zero emissions and consists of capturing CO2, transporting it, and sequestering it deep down into selected geological formations. Subsurface storage of carbon dioxide (CO2) depends on several factors like injectivity, formation characteristics, seal integrity, and the associated rock-fluid and fluid–fluid interactions, etc. One critical parameter, in this context, is the interfacial tension (IFT) of the fluid–fluid system in question i.e., CO2-brine IFT for CO2 geo-storage. While experimental data for IFT of CO2-brine systems have been rigorously reported, and a few studies generated robust correlations to forecast the IFT as a function of its influencing factors, still the correlations lack in terms of accuracy and consideration of the most up-to-date data inventory. This paper thus presents a robust and accurate artificial intelligence (AI) based model to estimate the IFT of CO2-brine systems based on the largest data set (2896 points) utilized so far. A range of intelligent models such as Gradient Boosting (GB), Neural Network (NN), and Genetic Programming (GP) are used here to predict CO2-brine IFT. Furthermore, the most influencing factors are evaluated by using the relevance factor analysis method that helps in determining the weight of the contribution of each parameter on IFT. Our results suggest that: a) Gradient Boosting (GB) model with all its derivatives demonstrates the best accuracy for IFT prediction with a high coefficient of determination (R2) equal to 0.964, b) lowest performance is attributed to GP, and c) the impact of different factors is found to be in the order pressure > temperature > salinity > impurities. Moreover, an improved IFT correlation as a function of thermophysical and chemical properties i.e., temperature, pressure, and salinity is presented to quantify IFT with high precision (R2 = 0.886 and MRAE = 0.295) and significant time saving. This correlation is further validated and results show that it can capture the several chemical and physical processes leading to the various behavior trends of IFT stated in the literature. As a direct application in CO2 geo-storage projects, our proposed correlation is used to determine the optimal storage depth of a real carbonate saline aquifer located onshore of UAE. This study thus provides a robust model to estimate CO2-brine IFT which is important for storage capacity estimations and helps to better understand the factors influencing IFT. The model proposed here captures the dependence of CO2-brine IFT on six independent variables including pressure, temperature, brine ionic strength, cation type, and presence of impurities (CH4 and N2).

Predicting mechanical properties of CO2 hydrates: machine learning insights from molecular dynamics simulations

Understanding the mechanical properties of CO2 hydrate is crucial for its diverse sustainable applications such as CO2 geostorage and natural gas hydrate mining. In this work, classic molecular dynamics (MD) simulations are employed to explore the mechanical characteristics of CO2 hydrate with varying occupancy rates and occupancy distributions of guest molecules. It is revealed that the mechanical properties, including maximum stress, critical strain, and Young’s modulus, are not only affected by the cage occupancy rate in both large 51262 and small 512 cages, but also by the distribution of guest molecules within the cages. Specifically, the presence of vacancies in the 51262 large cages significantly impacts the overall mechanical stability compared to 512 small cages. Furthermore, four distinct machine learning (ML) models trained using MD results are developed to predict the mechanical properties of CO2 hydrate with different cage occupancy rates and cage occupancy distributions. Through analyzing ML results, as-developed ML models highlight the importance of the distribution of guest molecules within the cages, as crucial contributor to the overall mechanical stability of CO2 hydrate. This study contributes new knowledge to the field by providing insights into the mechanical properties of CO2 hydrates and their dependence on cage occupancy rates and cage occupancy distributions. The findings have implications for the sustainable applications of CO2 hydrate, and as-developed ML models offer a practical framework for predicting the mechanical properties of CO2 hydrate in different scenarios.

Influence of carbon nanodots on the Carbonate/CO2/Brine wettability and CO2-Brine interfacial Tension: Implications for CO2 geo-storage

Understanding the interfacial and wettability phenomena of the CO2-brine and rock-CO2-brine system plays a key role in the geo-storage of CO2 and in their security containment. Carbon nanodots (CNDs) have been identified as a promising surface-active agent for altering the wettability from strongly oil-wet into water-wet in the carbonate reservoirs, thus it contributed for the oil recovery increment in the carbonate formations. However, no consideration was given to the application of CNDs for the enhancement of CO2 geological storage and containment security in the carbonate formations. In the current study, we assessed the impact of CNDs on the residual and structural trapping of CO2 in the carbonate reservoir. The contact angles (θ) of the CO2-brine-carbonate rock system were studied before and after the treatment of CNDs for both the clean and crude oil-aged samples. Subsequently, we also investigated the CO2-seawater interfacial tensions (IFT) with and without CNDs addition. All these measurements were performed as a function of CNDs concentration (0–1000 ppm), temperature (20–80 °C) and pressure (14.7–3000 psi). The results showed that the clean carbonate rock remained strongly water-wet before and after CNDs-treatment. The oil-wet carbonate sample was turned into CO2-wet at all investigated temperatures when the pressures increased to 1000 psi, however, it turns to be weakly water-wet upon treatment with CNDs at the highest pressure (3000 psi). Specifically, at 3000 psia and 20 °C, the contact angle of oil-wet carbonate reduced from 122° to 86° with the addition of CNDs at the increased concentration of 1000 ppm. Such wettability modifications in carbonate formations will enhance the efficacy of CO2 storage potential, and eventually, this will help to de-risk their security containment. The θ generally demonstrated a declining trend with the increase of CNDs concentration but it slightly increased with the rise in temperature and pressure. These results suggest that warmer reservoirs and increased storage depth could be unfavorable for CO2 storage in carbonate formations. Thus, the pre-injection of a minimal concentration of CNDs in the formation would improve CO2 storage effectively. Also, no significant change was observed in the CO2-seawater IFT in the presence of CNDs, which indicates that the capillary trapping of CO2 could be favorable due to their lower contact angle and high CO2-brine IFT as the most suitable condition to maintain the high capillarity. The study demonstrates that the highly stable, freely soluble, easy detectable, scalable, and economically viable CNDs has the potency to enhance the containment security of CO2 in carbonate formation.

An experimental study of CO2 injection strategies for enhanced oil recovery and geological sequestration in a fractured tight sandstone reservoir

Carbon dioxide enhanced oil recovery has been considered and tested in unconventional oil reservoirs due to its additional environmental benefits from simultaneous CO2 geological sequestration. However, it will require a proper injection strategy to overcome unfavorable sweep efficiency in CO2 displacement, which is even magnified in unconventional oil reservoirs due to strong heterogeneity caused by natural and artificial fractures. In this study, we investigated three immiscible CO2 injection strategies at reservoir conditions using tight fractured sandstone cores from the Ordos Basin, China: water alternative gas injection, cyclic CO2 injection, and CO2 foam/surfactant alternative gas injection. A pressurization and miscible CO2 injection were then added after each injection strategy to examine the influence of residual liquid distributions on the miscible displacement efficiency after the tested injection schemes. The core plugs with comparable porosity and permeability were selected, and all cores reached a similar recovery factor (∼11%) after primary CO2 flooding. We found that the cyclic CO2 injection had best performance, with the highest incremental and accumulative oil recovery at 23.6% and 32.26%. Its relatively higher sweep efficiency indicated a uniform CO2 distribution at the end of the cyclic injection, which further led to the highest incremental recovery of 4.94% in the following miscible injection. Comparable CO2 storage capacities were observed in the three fractured core samples (12.21%, 12.98%, and 9.71%, respectively) after completing the miscible displacements. In general, cyclic CO2 injection is recommended as an effective CO2 EOR and geo-storage in tight fractured rocks.

Comparative numerical study on the co-optimization of CO2 storage and utilization in EOR, EGR, and EWR: Implications for CCUS project development

Carbon capture, utilization, and storage (CCUS) and the geological sequestration of carbon dioxide (CO2) have become effective means of mitigating CO2 emissions and combating global warming. Currently, two main issues influence the implementation and progress of major CCUS technologies (e.g., CO2 geo-storage combined with CO2-enhanced oil recovery (CO2-EOR), CO2-enhanced gas recovery (CO2-EGR), and CO2-enhanced deep saline water/brine recovery (CO2-EWR)): high development costs and negative environmental impacts. Additionally, certain operating and reservoir critical parameters could influence the performance of CCUS technologies, making it difficult to design an optimal development scheme. In this study, a comparative numerical simulation analysis on the co-optimization of CO2 storage and utilization in EOR, EGR, and EWR was performed. A geological model based on the Bakken formation was built, and the influence of critical reservoir parameters (reservoir permeability, porosity, initial reservoir pressure, injection pressure, and production pressure) was observed through sensitivity analysis. The following results were obtained: (1) For CO2-EOR, the CO2 storage capacity increases with operating pressure above the minimum miscibility pressure. (2) Based on the best-case scenario, the CO2 storage capacities of EWR, EOR, and EGR were 189.4 × 106 scf, 252 × 106 scf, and 97 × 106 scf, respectively. (3) According to the best-case analysis, the recovery factor of EWR, EOR, and EGR were 5.2%, 91%, and 12%, respectively. (4) By comparing the best-case storage capacity and recovery factor, the optimal CCUS process was the CO2-EOR technology. The research results will guide future decisions on the development of CCUS projects.

Enhancing the CO2 trapping capacity of Saudi Arabian basalt via nanofluid treatment: Implications for CO2 geo-storage

Mineralization reactions in basaltic formations have gained recent interest as an effective method for CO2 geo-storage in order to mitigate anthropogenic greenhouse gas emissions. The CO2/rock interactions, including interfacial tension and wettability, are crucial factors in determining the CO2 trapping capacity and the feasibility of CO2 geological storage in these formations. The Red Sea geological coast in Saudi Arabia has many basaltic formations, and their wetting characteristics are rarely reported in the literature. Moreover, organic acid contamination is inherent in geo-storage formations and significantly impacts their CO2 geo-storage capacities. Hence, to reverse the organic effect, the influence of various SiO2 nanofluid concentrations (0.05–0.75 wt%) on the CO2-wettability of organic-acid aged Saudi Arabian (SA) basalt is evaluated herein at 323 K and various pressures (0.1–20 MPa) via contact angle measurements. The SA basalt substrates are characterized via various techniques, including atomic force microscopy, energy dispersive spectroscopy, scanning electron microscopy, and others. In addition, the CO2 column heights that correspond to the capillary entry pressure before and after nanofluid treatment are calculated. The results show that the organic acid-aged SA basalt substrates become intermediate-wet to CO2-wet under reservoir pressure and temperature conditions. When treated with SiO2 nanofluids, however, the SA basalt substrates become weakly water-wet, and the optimum performance is observed at an SiO2 nanofluid concentration of 0.1 wt%. At 323 K and 20 MPa, the CO2 column height corresponding to the capillary entry pressure increases from −957 m for the organic-aged SA basalt to 6253 m for the 0.1 wt% nano-treated SA basalt. The results suggest that the CO2 containment security of organic-acid-contaminated SA basalt can be enhanced by SiO2 nanofluid treatment. Thus, the results of this study may play a significant role in assessing the trapping of CO2 in SA basaltic formations.

Saudi Arabian basalt/CO2/brine wettability: Implications for CO2 geo-storage

Saudi Arabian basalt/CO2/brine wettability: Implications for CO2 geo-storage

The permeability of shale exposed to supercritical carbon dioxide

Permeability is a critical parameter of tight reservoir rocks and one of the important parameters for characterizing fluid flow and production from reservoirs. It determines the feasibility of its commercial development. SC-CO2 has been used in shale gas exploitation for efficient fracturing and the added benefit of CO2 geo-storage. And SC-CO2 plays an important role in permeability evolution of shale gas reservoirs. In this paper, Firstly, the permeability characteristics of shale under CO2 injection are discussed. The experimental results show that the relationship between permeability and gas pressure is not a single exponential relationship, but there is an obvious segmentation phenomenon, which is particularly obvious when it is close to the supercritical state, and the overall trend is first decreased and then increased. Subsequently, other specimens were selected for SC-CO2 immersion, and nitrogen was used to calibrate and compare shale permeability before and after treatment to assess changes in shale permeability after SC-CO2 treatment at pressures from 7.5 to 11.5 MPa and X-ray diffraction (XRD) analysis and scanning electron microscopy (SEM) were used to analyze the raw and CO2-treated shale particle sample, respectively. Results indicate the permeability increases significantly after SC-CO2 treated, and permeability growth is a linear function of SC-CO2 pressure. According to (XRD) analysis and (SEM) analysis, SC-CO2 not only can act as a solvent and dissolve carbonate minerals and clay minerals, but also can complex chemical reactions with mineral components in shale, Further dissolution of carbonate minerals and clay minerals, widened gas seepage channels and enhancing the permeability.

Dissolution of Forsterite Surface in Brine at CO2 Geo-storage Conditions: Insights from Molecular Dynamic Simulations

Evaluating the long-term security of geological deep saline aquifers to store CO2 requires a comprehensive understanding of mineral dissolution properties. Molecular dynamics simulations are performed to study the dissolution of forsterite in deep saline aquifers. The forsterite surface is found to be covered by three H2O molecular layers, hindering CO2 from directly contacting the surface. The dissolution rates at 350 K are increased by more than 1012 with the presence of Mg defects or salt ions in solutions. The more disordered surface in pure water caused by Mg defects accounts for the acceleration of dissolution, while absorbed Cl- ions on the surface in NaCl and KCl solutions accelerate the dissolution through electrostatic interactions. Comparatively, the frequent attacks from alkaline earth cations in MgCl2 and CaCl2 solutions to the surface contribute to the enhanced dissolution. In the acidic H3OCl solution, the electrostatic interactions between O atoms in H3O+ and the surface facilitate the dissolution. Interestingly, the ionic clusters of CO32-/HCO3- and Na+ in Na2CO3/NaHCO3 solution promote the dissolution process. This work provides molecular insights into forsterite dissolution in deep saline aquifers and guidance toward the optimization of CO2 geo-storage conditions.

Water wettability alternation of CO2-water-shale system due to nanoparticles: Implications for CO2 geo-storage

The wettability of rocks is closely related to the CO2 geo-storage (CGS) security after CO2 injection into the reservoir. Nanofluids can be used to efficaciously alter the wettability of the CO2-water-rock system toward an advantageous state (water-wet) for CGS. In this study, we investigated the potential of SiO2 and Al2O3 nanofluids at different aging time and concentrations to retain the wettability reversal of CO2-exposed shale from the Sichuan Basin after supercritical carbon dioxide (ScCO2) exposure. Fourier Transform Infrared Spectrometer and field emission scanning electron microscopy tests were performed to evaluate the variations of functional groups and surface topography of shale. Results indicated that both nanoparticles efficiently retain the wettability reversal of shale after a period of ScCO2 treatment, which is conducive to structural trapping in the CGS project. The efficiency was improved by increasing the nanofluid aging time and concentrations, while beyond a certain value, the contact angle value changed trivially. Quasi-homogeneously distributed on the shale surface in ScCO2 may contribute to the wettability alteration of shale in ScCO2, whereas there are still removals of nanoparticles in some sites. The variations of functional groups suggest that the existence of nanoparticles may mildly expedite the CO2 mineralization, signifying the change of wetting behavior of shale in ScCO2 depends on the wettability of nanoparticles, and the nanofluids treatment may exert a positive influence on mineral trapping in the CGS project. The findings in this research provide an important basis for raising the CO2 geological storage security and potential via nanofluids.

Impacts of relative permeability hysteresis, wettability, and injection/withdrawal schemes on underground hydrogen storage in saline aquifers

Underground hydrogen storage (UHS) is a key strategy in the implementation of a large-scale hydrogen (H2) economy and promotion of renewable energy development/utilization. For UHS in water-wet saline aquifers, H2 displaces in-situ brine during injection; during well shut-in and H2 withdrawal,brine imbibes back into the flow paths where it displaces some H2. These processes are influenced by H2-brine transport physics, H2-brine-rock interactions and injection/withdrawal schemes, which, in turn, determine H2 storage capacities and injection/withdrawal efficiency. However, these effects are poorly understood. Therefore, this work focuses onthe impact of relative permeability hysteresis (RPH), wettability, and H2 withdrawal rate on UHS performance in a saline aquifer. Furthermore, differences between UHS and CO2 geo-storage (CGS) are examined.The primary findings include: 1) RPH results in a smaller H2 withdrawal factor (H2-WF), but a larger H2 withdrawal purity (H2-WP); 2) H2-WF increases with rock hydrophobicity, while H2-WP is mostly insensitive to rock wettability; 3) under similar storage conditions, H2-WF and H2-WP are approximately 10% less than CO2-WF and CO2-WP.These insights demonstrate the significance ofRPH and rock wettability on UHS performance and provides guidance on H2 injection/withdrawal scheme optimization. This study aids in the implementation of an industry-scale hydrogen economy.

Impact of nanoparticles–surfactant solutions on carbon dioxide and methane wettabilities of organic-rich shale and CO2/brine interfacial tension: Implication for carbon geosequestration

Rock wetting behaviour and CO2/brine interfacial tension (IFT) have significant impacts on enhanced hydrocarbon recovery (EOR) and carbon geo-sequestration (CGS) projects. Influence of nanoparticles/surfactant solutions (NPS) flooding on EOR and CGS in sandstone and carbonate formation have been examined in recent studies. But the impact of NPS on carbon dioxide (CO2) and methane (CH4) wettabilities of organic-rich shale and CO2/brine IFT is presently unclear. Thus, we measured contact angles, [advancing (θa) and receding (θr)] for CO2/brine and CH4/brine on Marcellus shale with high total organic carbon (14.8 wt%), as well as CO2/brine IFT with Krüss drop shape analyzer (DSA 100) through the sessile drop and pendant drop techniques. Prior to IFT and contact angles measurement, the shale samples were aged in NPS solutions to evaluate the impact of NPS treatment on CO2 geo-storage. Low-cost rice husk silica nanoparticles and saponin surfactant were used for the study due to their environmental friendliness and economic attractiveness. At geo-storage conditions (25 MPa and 353 K), the advancing contact angle of untreated shale was measured as θa=116.22° (CO2-wet condition), whereas the receding contact angle was measured as θr=82.88° (near neutral wettability). However, θa reduced by 56.34° whereas θr reduced by 56.76° when the shale substrate was treated with 0.1 wt% SiO 2 and 0. 2 wt% saponin solutions. CO2/NPS IFT were lower than CO2/brine IFT and the CH4 wettability of the Marcellus shale was significantly lower than the CO2 wettability at all investigated conditions. Contact angles decreased with temperature and increased with CO2/CH4 pressure, whereas CO2/NPS IFT exhibited an opposite trend. The reduction in contact angles and CO2/brine IFT by NPS have significant impacts on adsorption trapping of CO2 in organic-rich shale and hydrocarbon recovery from unconventional shale reservoirs.