CO2 Wettability Research Articles

Enhancing carbon sequestration: Innovative models for wettability dynamics in CO2-brine-mineral systems

This study investigates the application of machine learning techniques—specifically convolutional neural networks, multilayer perceptrons and cascaded forward neural networks —to understand the wettability of the CO2/brine/rock system, a critical factor in carbon dioxide (CO2) capture, utilization, and storage in deep saline aquifers. Understanding wettability is essential for improving the efficacy of CO2 storage. The study incorporates variables such as salinity, mineral types, measurement methods, pressure, and temperature into the machine learning models. Using a dataset of 876 samples from existing literature, the proposed models were trained and optimized using the Adam optimizer, Levenberg-Marquardt algorithm, and particle swarm optimization respectively.The performance of these models was evaluated through plot analysis, statistical indicators, and the Taylor diagram, demonstrating a high level of accuracy compared to experimental data. The specifically convolutional neural networks model showed exceptional accuracy in predicting CO2 wettability in brine, with a root mean square error of 0.9612 and coefficient of determination value of 0.9982. The minimal presence of outliers in the specifically convolutional neural networks model further confirms its robustness.This research highlights the effectiveness of deep learning in modeling complex wettability behaviors in CO2-brine-mineral systems, offering substantial insights for enhancing carbon dioxide (CO2) capture, utilization, and storage strategies. The novelty of this work lies in its comprehensive integration of multiple variables and the use of advanced machine learning optimization techniques, going beyond previous efforts by achieving higher predictive accuracy and providing a more detailed understanding of wettability dynamics.

Nano structure of CO2-Brine-Kaolinite Interface: Implications for CO2 Geological Sequestration

CO2-Brine-Rock interaction has been identified to govern CO2 multiphase flow and affect the integrity of the underground reservoirs. However, limited investigations address the role of brine salinity, rock mineralogy, and organic matter in CO2 wettability at nano scale. To solve this problem, a molecular dynamics (MD) simulation is performed. The interfacial properties, including density distribution and radial distribution function (RDF, g(r)), are calculated for CO2 saturated high salinity water and CO2 saturated low salinity water. The density distribution profile shows that mineralogy is a critical parameter for CO2 wettability: lowering salinity leads to a more CO2 wet siloxane surface while the aluminol surface becomes less CO2 wet. g(r) reveals that the type of organic matter plays a critical role: base functional group (-N) renders a CO2 wet surface whereas the acid functional group (-COOH) causes a water wet surface. This investigation integrates the effects of brine salinity, mineralogy, and organic matter to evaluate CO2 wettability. This MD simulation reveals the principal factors controlling the CO2 wettability at the nano scale and provides a general paradigm to reduce the leakage risk of CO2 geological sequestration.

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.

CO2-philicity to CO2-phobicity Transition on Smooth and Stochastic Rough Cu-like Substrate Surfaces.

CO2 on metal substrates is essential to CO2 liquefaction and transportation of CO2, yet the manipulation of the wettability of the CO2 and the elucidation of its underlying mechanism have not been fully achieved. Here, using molecular dynamics simulations, we report CO2 wetting characteristics on both smooth and stochastic rough Cu-like substrate surfaces. The results indicate that the apparent contact angle (CA) of the CO2 droplet on the smooth surface decreases from 180° to 0° as the CO2-solid characteristic interaction energy increases from 0.002 to 0.016 eV. In addition, the CAs become greater with increasing the density of surface asperities, regardless of the intrinsic surface wettability. This is attributed to the capillary drying-out of liquid CO2 molecules in gaps between surface asperities at the three-phase contact line of the droplet, which is usually overlooked in previous theoretical studies. Notably, the intrinsically CO2-philic surface transforms to the CO2-phobic due to an increase in the density of surface rugosity. Moreover, we verify the range of applicability of the CA prediction models concerning the nanoscale asperities. This work is beneficial for fully understanding the influence of nanoscale surface topography on CO2 wettability and shedding light on the design of functionalized and patterned surfaces to manipulate CO2 wettability.

Predicting wettability of mineral/CO2/brine systems via data-driven machine learning modeling: Implications for carbon geo-sequestration

Effectively storing carbon dioxide (CO2) in geological formations synergizes with algal-based removal technology, enhancing carbon capture efficiency, leveraging biological processes for sustainable, long-term sequestration while aiding ecosystem restoration. On the other hand, geological carbon storage effectiveness depends on the interactions and wettability of rock, CO2, and brine. Rock wettability during storage determines the CO2/brine distribution, maximum storage capacity, and trapping potential. Due to the high CO2 reactivity and damage risk, an experimental assessment of the CO2 wettability on storage/caprocks is challenging. Data-driven machine learning (ML) models provide an efficient and less strenuous alternative, enabling research at geological storage conditions that are impossible or hazardous to achieve in the laboratory. This study used robust ML models, including fully connected feedforward neural networks (FCFNNs), extreme gradient boosting, k-nearest neighbors, decision trees, adaptive boosting, and random forest, to model the wettability of the CO2/brine and rock minerals (quartz and mica) in a ternary system under varying conditions. Exploratory data analysis methods were used to examine the experimental data. The GridSearchCV and Kfold cross-validation approaches were implemented to augment the performance abilities of the ML models. In addition, sensitivity plots were generated to study the influence of individual parameters on the model performance. The results indicated that the applied ML models accurately predicted the wettability behavior of the mineral/CO2/brine system under various operating conditions, where FCFNN performed better than other ML techniques with an R2 above 0.98 and an error of less than 3%.

Residual trapping of CO2, N2, and a CO2-N2 mixture in Indiana limestone using robust NMR coreflooding: Implications for CO2 geological storage

Carbon capture and sequestration (CCS) in geological formations is a prominent solution for reducing anthropogenic carbon emissions and mitigating climate change. The capillary trapping of CO2 is a primary trapping mechanism governed by the pressure difference between the wetting and nonwetting phases in a porous rock, making the latter a key input parameter for dynamic simulation models. During the CCS operational process, however, the CO2 is prone to contamination by impurities from various sources such as surfaces (e.g., pipelines and tanks) and the subsurface (e.g., existing natural gas). Such contamination can strongly influence the overall CO2 wettability, storage capacity, and containment security. Hence, the present study uses the nuclear magnetic resonance (NMR) core flooding technique to investigate and compare the residual saturations of pure CO2, pure N2, and a 50:50 CO2/N2 mixture in an Indiana limestone. The longitudinal and transverse relaxation times (T1 and T2) are measured to examine the displacement process of the pore network, and the trapping mechanism is evaluated at the pore scale as a determinant of the field-scale flow behavior. The NMR T1-T2 and 2D maps are used to observe the fluid configurations in the pore network, and the T1/T2 ratios are used to evaluate the microscopic wettability of the limestone grains by the pore-space fluids following each drainage/imbibition process step. The results indicate substantial residual gas trapping in the rock for the CO2-brine, N2-brine, and CO2/N2-brine systems, corresponding to gas saturations of 25%, 27%, and 26%, respectively. In the CO2-brine system, the intermolecular interplay between the CO2-enriched brine and limestone grains results in a higher T1/T2 ratio and significantly reduces the hydrophilicity of the limestone. Furthermore, the NMR T2 distribution reveals the occurrence of preferential water displacement into the large pores (r > 1 µm) and from the intermediate pores (0.03 µm < r < 1 µm), whereas water remains immobile in the smaller pores (r < 0.03 µm). The insignificant difference in residual trapping saturation between pure CO2 and the CO2-N2 mixture indicates the potential to allow for impurities in the CO2 phase in CCS without reducing the residual trapping capacity. Thus, the present work provides comprehensive information on the impact of gas injection on residual gas trapping in subsurface geological formations at the pore scale, thereby aiding in the development of CCS and other potential applications in enhanced oil recovery (EOR).

Surface wettability of sandstone and shale: Implication for CO2 storage

Reservoir wettability is an important factor controlling the CO2 geosequestration. In this study, temperature pressure and salinity effects were implemented to analyze the CO2 wettability alteration of the sandstone and shale reservoir. Previous studies on CO2 sequestration were mostly from the point of view of caprock wettability. This research is from the point of view of caprock and reservoir wettability, considers the sandstone and shale interbeded situation, which is less studied. Research results show that the contact angle of CO2/sandstone and CO2/shale decreases with pressure, which indicates that the reservoir is more CO2-wet in high pressure. In addition, the contact angle was not related to the temperature. Thirdly, the sandstones show strong hydrophilicity that has little relation with liquid salinity under standard temperature and pressure. Compared with sandstones, the hydrophilicity of the shales is weak. The CO2 wettability of shales increase with the salinity, due to the reason that shales have higher clay content and better oil saturation than the sandstones. Tests predict that low-pressure sandstone is suitable for the caprocks, high-pressure-low-temperature sandstone with better oil saturation, high-pressure-high-temperature sandstone with poor oil saturation, and low-temperature-high-pressure shale are ideal for CO2 storage.

Influence of stearic acid and alumina nanofluid on CO2 wettability of calcite substrates: Implications for CO2 geological storage in carbonate reservoirs

HypothesisAtmospheric CO2 emissions trigger global warming and climate change challenges. Thus, geological CO2 storage appears to be the most viable choice to mitigate CO2 emissions in the atmosphere. However, the adsorption capacity of reservoir rock in the presence of diverse geological conditions, including organic acids, temperature, and pressure, can cause reduced certainty for CO2 storage and injection problems. Wettability is critical in measuring the adsorption behavior of rock in various reservoir fluids and conditions. ExperimentWe systematically evaluated the CO2-wettability of calcite substrates at geological conditions (323 K and 0.1, 10, and 25 MPa) in the presence of stearic acid (a replicate realistic reservoir organic material contamination). Similarly, to reverse the effects of organics on wettability, we treated calcite substrates with various alumina nanofluid concentrations (0.05, 0.1, 0.25, and 0.75 wt%) and evaluated the CO2-wettability of calcite substrates at similar geological conditions. FindingsStearic acid profoundly affects the contact angle of calcite substrates where wettability shifts from intermediate to CO2-wet conditions, reducing the CO2 geological storage potential. The treatment of organic acid-aged calcite substrates with alumina nanofluid reversed the wettability to a more hydrophilic state, increasing CO2 storage certainty. Further, the optimum concentration displaying the optimum potential for changing the wettability in organic acid-aged calcite substrates was 0.25 wt%. The effect of organics and nanofluids should be augmented to improve the feasibility of CO2 geological projects at the industrial scale for reduced containment security.

Effect of Organic Acids on CO2 Trapping in Carbonate Geological Formations: Pore-Scale Observations Using NMR

Stearic acid is an example of a carboxylic compound naturally present in geological formations (deep saline aquifers and depleted hydrocarbon reservoirs), which renders the rock hydrophobic (CO2-wet) over a geological time scale. Such hydrophobic surfaces are detrimental to residual CO2 trapping. There is, however, a lack of comprehensive dataset about how traces of these organic molecules affect the rock′s CO2 wettability and residual CO2 trapping. We, thus, used in situ NMR T1–T2 2D images to visualize fluid configurations in the pore network and used T1/T2 ratios to assess the microscopic wettability of the rock to pore space fluids subsequent to each process step. The T2 relaxation time was measured to demonstrate displacement processes and evaluate the trapping behavior at the pore scale, which is closely correlated to reservoir-scale flow functions. The trapping in the CO2-wet sample (14%) was significantly lower than that of the analogous water-wet sample (18%). This reduction in CO2 trapping is due to surface macroscopic flow layers acting as conduits allowing slow desaturation of CO2. Importantly, in the CO2-wet sample, trapping predominately occurred in meso- and micropores, whereas trapping in the analogous water-wet rock primarily occurred in macropores. This work thus provides a comprehensive dataset on the impact of organic acids on residual trapping at the pore scale, which ultimately helps to advance industrial-scale implementation of CGS and EOR project schemes in carbonate reservoirs.

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.

Effects of Anisotropy and CO2 Wettability on CO2 Storage Capacity in Sandstone

The geological sequestration of carbon dioxide (CO2) is an alternative strategy for mitigating global warming. The CO2 storage capacity is often characterized by the capillary pressure curve, which in turn depends on the pressure and temperature of the injected CO2 and the internal structure of the reservoir rocks. The key structural feature that influences the storage capacity in porous rocks is their inherent anisotropy. An experimental study was performed to investigate the optimal conditions for CO2 injection into an anisotropic sandstone. The capillary pressure curve and the residual CO2 saturation were determined by injecting three CO2 phases into the directionally cored sandstone specimens with different flow rates. The CO2 saturation in sandstone increased with increasing flow rate, resulting in asymptotic values. The storage capacity of CO2 was the highest in the order of liquid CO2 (LCO2), supercritical CO2 (scCO2), and gaseous CO2 (gCO2). It was also the highest when the direction of CO2 injection was normal in relation to the embedded sandstone layers. The in situ cored sandstone from the Janggi Basin in Korea was further tested to examine the effect of its pore size on the capillary pressure of CO2.

CO2 utilization and sequestration in Reservoir: Effects and mechanisms of CO2 electrochemical reduction

Owing to the harmful consequences of the greenhouse effect, mankind has reached a consensus to reduce CO2 emissions. CO2 utilization and sequestration is considered the most feasible solution for realizing an effective and economical sequestration of CO2. Herein, CO2-enhanced oil recovery (EOR) is a representative strategy owing to its tremendous sequestration capacity and reasonable economic viability. However, the low sequestration stability and the accompanying secondary disasters have hindered its wider application. Considering this, a novel CO2 utilization and sequestration technology, i.e., CO2 electrochemical reduction (CO2RR)-EOR technology was proposed and its effects and mechanisms were studied. First, a SnO2 catalyst that can be used in the coreflooding experiments was synthesized and its efficiency on CO2RR was evaluated. Then, coreflooding experiments using the SnO2 catalyst were conducted to study the influence of CO2RR on the CO2 sequestration and oil recovery. Next, contact angle and interfacial tension were measured to analyze the effect of the CO2RR on the CO2-crude oil-brine-rock interaction. Finally, the CO2RR-EOR mechanism was proposed. Multiple experiments revealed that the low-cost and easy-synthesis SnO2 catalyst, which was characterized by the 3-dimensioned hierarchical and porous structure, was in the high efficiency and strong stability. Coreflooding results illustrated that the CO2RR remarkably enhanced CO2 sequestration and oil recovery. At the optimal cell potential of 3.75 V, the CO2 sequestration efficiency and oil recovery were as high as 75.93% and 43.8%, respectively, which are much higher than those (50.56% and 37.9%, respectively) achieved in conventional CO2 flooding. Contact angle and interfacial tension results indicated that the CO2RR has a significant impact on the CO2-crude oil-brine-rock interaction. At the optimal cell potential, the crude oil-contact angle and the interfacial tension were 36.2° and 8.9 mN/m, respectively, which are much lower than those (64.6° and 16.4 mN/m, respectively) achieved in conventional CO2 flooding; the CO2-contact angle was 52.2°, which too is much larger than that (31.7°) achieved in conventional CO2 flooding. In this technology, the CO2RR converts the injected CO2 into formate to sequestrate itself, and meanwhile alters the CO2-crude oil-brine-rock interactions, resulting in enhanced CO2 wettability and consequently increases CO2 trapping and retention; causing the weakened oil wettability and the enhanced oil-brine interaction, and finally enhances oil recovery. CO2RR-EOR can be a novel, efficient, and economically-viable CO2 utilization and sequestration technology, which provide a feasible option for the future industrial CO2 emission reduction.

Study on the Ways to Improve the CO2-H2O Displacement Efficiency in Heterogeneous Porous Media by Lattice Boltzmann Simulation.

To improve the efficiency of CO2 geological sequestration, it is of great significance to in-depth study the physical mechanism of the immiscible CO2–water displacement process, where the influential factors can be divided into fluid–fluid and fluid–solid interactions and porous media characteristics. Based on the previous studies of the interfacial tension (capillary number) and viscosity ratio factors, we conduct a thorough study about the effects of fluid–solid interaction (i.e., wettability) and porous media characteristics (i.e., porosity and non-uniformity of granule size) on the two-phase displacement process by constructing porous media with various structural parameters and using a multiphase lattice Boltzmann method. The displacement efficiency of CO2 is evaluated by the breakthrough time characterizing the displacement speed and the quasi-steady state saturation representing the displacement amount. It is shown that the breakthrough time of CO2 becomes longer, but the quasi-steady state saturation increases markedly with the increase in CO2 wettability with the surface, demonstrating an overall improvement of the displacement efficiency. Furthermore, the breakthrough time of CO2 shortens and the saturation increases significantly with increasing porosity, granule size, and non-uniformity, showing the improvement of the displacement efficiency. Therefore, enhancing the wettability of CO2 with the surface and selecting reservoirs with greater porosity, larger granule size, and non-uniformity can all contribute to the efficiency improvement of CO2 geological sequestration.

Influence of Humic acids on CO2-quartz wettability: Implications for CO2 storage

Carbon Geo Sequestration (CGS) is considered an effective way to reduce anthropogenic greenhouse gas emission into the atmosphere. The storage of captured CO2 is mainly geological. Several researchers confirmed Humic Acid (HA) concentration in the deep aquifer at high temperature and high-pressure conditions, which may affect the rock wettability and reduce storage capacities and containment security. One key parameter which affects the wettability of formation in the presence of humic acid is pH. However, there is a lack of information on the relationship of pH, humic acid and wettability of CO2 in storage formation. We measured the effect of pH on the CO2 wettability of storage formation in the presence of humic acid. Advancing and receding contact angles were measured at HPHT conditions (pressure of 12 MPa and temperature of 323 K), using the pendant drop tilted-plate method for various pH (2 to 12) at the humic acid concentration (25 mg/L) and brine salinities (0 and 0.2 M NaCl). We concluded that decreasing pH significantly impacts rock wettability; and shifts water-wet to CO2-wet, thus reducing structural and residual trapping capacities. Therefore, presence of organic acids in reservoir geochemical conditions should be considered to de-risk the development of CGS projects.

Dynamic fluid interactions during CO2-ECBM and CO2 sequestration in coal seams. Part 2: CO2-H2O wettability

In addition to CO2-CH4 interactions (Part 1), the success of CO2 enhanced coalbed methane (CO2-ECBM) and geological sequestration are significantly affected by the CO2-H2O wettability. Wettability controls both gas desorption and transport and is influenced by injection pressure, reservoir temperature and the state of water that is present – as either adsorbed- or free-water. Dynamic changes in wettability remains poorly constrained – due to the innate difficulty and invasive nature of conventional measurements (e.g., captive gas bubble and pendent drop tilted plate methods). In part 2, we use nuclear magnetic resonance (NMR) as a non-invasive method to explore the mechanisms of these factors (pressure, temperature, water-state) on CO2-H2O wettability during CO2-ECBM. Results for contrasting subbituminous coal and anthracite show that the CO2 wettability of coals significantly increases with increasing CO2 injection pressure up to 5 MPa before stabilizing to a limiting value. This suggests that the most economically-suitable injection pressure is ~5 MPa. CO2 wettability also increases with a decrease in temperature suggesting that shallower reservoirs may be marginally improved in this trend. Additionally, the presence of non-adsorbed water in coals significantly reduces both the sensitivity of CO2 wettability to pressure and the absolute magnitude of wettability relative to the case where free-water is absent. Thus, draining free-water from the reservoir will serve the dual purposes of both increasing gas transport and the potential for desorption from the perspective of CO2-H2O wettability. The far-reaching results in this study, together with the companion paper (Part 1) are significant for evaluating CO2-ECBM improvement both in enhancing methane recovery and CO2 utilization in coals.

The interfacial properties of clay-coated quartz at reservoir conditions

Shale interfacial properties are important for CO2 geo-sequestration and CH4 recovery in shale formation. In this work we use a newly-developed and well-defined shale model (i.e. a clay-coated quartz) to systematically evaluate the influence of kaolinite and montmorillonite, as primary constituents of shales, on CO2 shale-wettability, and shale-CO2, shale-CH4, and shale-water surface energies. Specifically, we measure CO2 wettability of clay-coated quartz and the related CO2-brine and CH4–brine interfacial tensions at various pressures and temperatures. We calculate the surface free energies of the clay-coated quartz versus CO2 and CH4 using Neumann’s equation. The results demonstrate that clay coating leads to a less hydrophilic surface at a low temperature (i.e. 300 K), while it renders the surface more hydrophilic at a high temperature (i.e. 353 K); however, clay coating has only a small influence on the quartz-CO2 and quartz-CH4 surface energies. In addition, higher CO2 pressures always result in less water-wet surfaces for clean, kaolinite-coated and montmorillonite-coated quartz samples at the temperatures tested (i.e. 300 K and 353 K). Moreover, higher CO2 and CH4 pressures lead to smaller mineral-CO2 and mineral-CH4 surface energies, respectively. An increase in temperature shows a complicated effect, i.e. it increases the surface energies of mineral-CO2 while it reduces those of mineral-CH4 (slightly) and clay-coated quartz-brine systems. For similar pressure and temperature values, the surface energies of mineral-CO2 system are always smaller than those of the corresponding mineral-CH4 systems. The results can aid the predictions of CO2 storage capacity, leakage risk assessments, and CH4 recovery.

Modeling CO2 wettability behavior at the interface of brine/CO2/mineral: Application to CO2 geo-sequestration

Carbon capture and storage (CCS) has been introduced as an effective method for reduction of CO2 emissions to the atmosphere. While different aspects and controlling parameters of geological CO2 sequestration process are well understood, there is still large uncertainty regarding brine/CO2/rock wettability and no model has yet been presented for characterizing the contact angle of brine/CO2/rock system at different environmental conditions. In this study, various intelligent models have been developed for accurate estimation of brine/CO2/rock contact angles. Results demonstrated that the proposed models have the ability to accurately simulate the brine/CO2 wettability behavior for quartz, calcite, feldspar, and mica minerals at different pressures, temperatures and salinities. Additionally, results revealed that adaptive neuro-fuzzy interference system has the best performance compared with the other models and its superiority is shown through statistical and graphical analyses. Afterward, the most effective input parameters on brine/CO2/rock wettability were investigated by employing Monte-Carlo algorithm, which showed that mineral type, salinity and pressure are the most sensitive variables for this process. As wettability can highly affect the residual and structural trapping mechanisms during carbon geo-sequestration, presenting reliable models for estimating brine/CO2/rock wettability is crucial. Therefore, the outcomes of this study can be useful for accurate estimation of these mechanisms capacity.

Uncertainty in fault seal parameters: implications for CO&amp;lt;sub&amp;gt;2&amp;lt;/sub&amp;gt; column height retention and storage capacity in geological CO&amp;lt;sub&amp;gt;2&amp;lt;/sub&amp;gt; storage projects

Abstract. Faults can act as barriers to fluid flow in sedimentary basins, hindering the migration of buoyant fluids in the subsurface, trapping them in reservoirs, and facilitating the build-up of vertical fluid columns. The maximum height of these columns is reliant on the retention potential of the sealing fault with regards to the trapped fluid. Several different approaches for the calculation of maximum supported column height exist for hydrocarbon systems. Here, we translate these approaches to the trapping of carbon dioxide by faults and assess the impact of uncertainties in (i) the wettability properties of the fault rock, (ii) fault rock composition, and (iii) reservoir depth on retention potential. As with hydrocarbon systems, uncertainties associated with the wettability of a CO2–brine–fault rock system for a given reservoir have less of an impact on column heights than uncertainties of fault rock composition. In contrast to hydrocarbon systems, higher phyllosilicate entrainment into the fault rock may reduce the amount of carbon dioxide that can be securely retained due a preferred CO2 wettability of clay minerals. The wettability of the carbon dioxide system is highly sensitive to depth, with a large variation in possible column height predicted at 1000 and 2000 m of depth, which is the likely depth range for carbon storage sites. Our results show that if approaches developed for fault seals in hydrocarbon systems are translated, without modification, to carbon dioxide systems the capacity of carbon storage sites will be inaccurate and the predicted security of storage sites erroneous.

Investigations of CO2-water wettability of coal: NMR relaxation method

Carbon geo-sequestration (CGS) and recovery enhancement with carbon dioxide injection (CO2-ECBM) have brought increasing focus on the CO2 and water wettability of coal. The CO2 and water contact angles measured using existing conventional methods, such as the pendent drop tilting plate technique and the captive-bubble technique, show low reproducibility due to coal heterogeneity and operational complexity. In this study, a novel NMR-based approach was developed to evaluate the CO2 and water wettability of coal. The experimental results of nine bituminous and anthracite coals show that water wettability can be linearly correlated with the changes of the T2 spectra peak positions. Based on the measured contact angle from the profile of the water adhering to the coal powder disc and the T2 from the NMR of coal powder, we proposed a linear formulation to evaluate the contact angle using the change of T2g of P3. Using this method, we analyzed the CO2-water wettability characteristics of coal. The results show that CO2 reduces the water wettability of coal. Low temperature and/or high CO2 pressure can enhance the CO2 wettability of coal. The change of water-coal wetting behavior with injection of CO2, is resulted by three factors: change of CO2 adsorption capacity of coal, change of interfacial tension, and dissolution of CO2 in water. This study makes it possible to evaluate changes in the water and CO2 wettability of coal, which is essential for evaluating the fluid-interaction mechanisms during the process of carbon geo-sequestration and enhanced coalbed methane recovery with carbon dioxide injection.

Influence of shale‐total organic content on CO2 geo‐storage potential

AbstractShale CO2 wettability is a key factor which determines the structural trapping capacity of a caprock. However, the influence of shale‐total organic content (TOC) on wettability (and thus on storage potential) has not been evaluated despite the fact that naturally occurring shale formations can vary dramatically in TOC, and that even minute TOC strongly affects storage capacities and containment security. Thus, there is a serious lack of understanding in terms of how shale, with varying organic content, performs in a CO2 geo‐storage context. We demonstrate here that CO2‐wettability scales with shale‐TOC at storage conditions, and we propose that if TOC is low, shale is suitable as a caprock in conventional structural trapping scenarios, while if TOC is ultrahigh to medium, the shale itself is suitable as a storage medium (via adsorption trapping after CO2 injection through fractured horizontal wells).