Residual trapping of supercritical CO2 in oil-wet sandstone

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%.

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.

Influence of organic molecules on wetting characteristics of mica/H2/brine systems: Implications for hydrogen structural trapping capacities

HYPOTHESIS

Actualization of the hydrogen (H₂) economy and decarbonization goals can be achieved with feasible large-scale H₂ geo-storage. Geological formations are heterogeneous, and their wetting characteristics play a crucial role in the presence of H₂, which controls the pore-scale distribution of the fluids and sealing capacities of caprocks. Organic acids are readily available in geo-storage formations in minute quantities, but they highly tend to increase the hydrophobicity of storage formations. However, there is a paucity of data on the effects of organic acid concentrations and types on the H₂-wettability of caprock-representative minerals and their attendant structural trapping capacities.

EXPERIMENT

Geological formations contain organic acids in minute concentrations, with the alkyl chain length ranging from C₄ to C₂₆. To fully understand the wetting characteristics of H₂ in a natural geological picture, we aged mica mineral surfaces as a representative of the caprock in varying concentrations of organic molecules (with varying numbers of carbon atoms, lignoceric acid C₂₄, lauric acid C₁₂, and hexanoic acid C₆) for 7 days. To comprehend the wettability of the mica/H₂/brine system, we employed a contact-angle procedure similar to that in natural geo-storage environments (25, 15, and 0.1 MPa and 323 K).

FINDINGS

At the highest investigated pressure (25 MPa) and the highest concentration of lignoceric acid (10^-2 mol/L), the mica surface became completely H₂ wet with advancing (θ_a= 106.2°) and receding (θ_r=97.3°) contact angles. The order of increasing θ_a and θ_r with increasing organic acid contaminations is as follows: lignoceric acid > lauric acid > hexanoic acid. The results suggest that H₂ gas leakage through the caprock is possible in the presence of organic acids at higher physio-thermal conditions. The influence of organic contamination inherent at realistic geo-storage conditions should be considered to avoid the overprediction of structural trapping capacities and H₂ containment security.

Flow and structural analysis of sedimentary rocks by core flooding and nuclear magnetic resonance: A review

Fluid flow analyses and investigations of associated structural variations in rock formations are important due to the complex nature of rocks and the high heterogeneity that exists within fluid-rock systems. Variations in fluid-rock parameters need to be ascertained over time with continuous or cyclic fluid injection into subsurface rocks for enhanced oil recovery and other subsurface applications. This Review introduces the use of the core flooding-nuclear magnetic resonance (NMR) technique for analysis of combined fluid flow and structural features in subsurface fluid-rock systems. It presents a summary of the results realized by various researchers in this area of study. The influence of several conditions, such as geochemical interactions, wettability, inherent heterogeneities in fluid flow and rock properties, and variations in these parameters, is analyzed. We investigate NMR measurements for both single fluid phase saturation and multiphase saturation. Additionally, the processes for identifying and distinguishing different fluid phases are emphasized in this study. Furthermore, capillary pressure and its influence on fluid-rock parameters are also discussed. Although this study emphasizes subsurface rocks and enhanced oil recovery, the experimental combination is also extended to core flooding using several other injection fluids and porous media. Finally, research gaps pertaining to core flooding-NMR systems regarding fluid flow, structural changes, fluid-rock systems, and instrumentation are pointed out. Transient flow analysis involving structural variations is suggested for future work in this regard.

Pore wettability for enhanced oil recovery, contaminant adsorption and oil/water separation: A review

Wettability, a fundamental property of porous surface, occupies a pivotal position in the fields of enhanced oil recovery, organic contaminant adsorption and oil/water separation. In this review, wettability and the related applications are systematically expounded from the perspectives of hydrophilicity, hydrophobicity and super-wettability. Four common measurement methods are generalized and categorized into contact angle method and ratio method, and influencing factors (temperature, the type and layer charge of matrix, the species and structure of modifier) as well as their corresponding altering methods (inorganic, organic and thermal modification etc.) of wettability are overviewed. Different roles of wettability alteration in enhanced oil recovery, organic contaminant adsorption as well as oil/water separation are summarized. Among these applications, firstly, the hydrophilic alteration plays a key role in recovery of the oil production process; secondly, hydrophobic circumstance of surface drives the organic pollutant adsorption more effectually; finally, super-wetting property of matrix ensures the high-efficient separation of oil from water. This review also identifies importance, challenges and future prospects of wettability alteration, and as a result, furnishes the essential guidance for selection and design inspiration of the wettability modification, and supports the further development of pore wettability application.

Influence of Organic Acid Concentration on Wettability Alteration of Cap-Rock: Implications for CO2 Trapping/Storage

Every year, millions of tons of CO₂ are stored in CO₂-storage formations (deep saline aquifers) containing traces of organic acids including hexanoic acid C₆ (HA), lauric acid C₁₂ (LuA), stearic acid C₁₈ (SA), and lignoceric acid C₂₄ (LiA). The presence of these molecules in deep saline aquifers is well documented in the literature; however, their impact on the structural trapping capacity and thus on containment security is not yet understood. In this study, we therefore investigate as to how an increase in organic acid concentration can alter mica water wettability through an extensive set of experiments. X-ray diffraction (Figure S2), field emission scanning electron microscopy, total organic carbon analysis, Fourier-transform infrared spectroscopy, atomic force microscopy, and energy-dispersive X-ray spectroscopy were utilized to perceive the variations in organic acid surface coverage with stepwise organic acid concentration increase and changes in surface roughness. Furthermore, thresholds of wettability that may indicate limits for structural trapping potential (θ_r < 90°) have been discussed. The experimental results show that even a minute concentration (∼10^-5 mol/L for structural trapping) of lignoceric acid is enough to affect the CO₂ trapping capacity at 323 K and 25 MPa. As higher concentrations exist in deep saline aquifers, it is necessary to account for these thresholds to derisk CO₂-geological storage projects.

The influence of temperature on wettability alteration during CO2 storage in saline aquifers

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Impact of temperature on the wettability

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Impact of temperature on relative permeability curves

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Impact of relative permeability curves on CO2 solubility

The wettability of a formation is defined as the tendency of one fluid to spread on a surface in competition with other fluids which are also in contact with it. However, the impact of temperature on wettability in an aquifer and the modification of relative permeability curves based on the temperature variation in aquifers is not well covered in the literature. This study redresses this dearth of information by investigating the impact of temperature on wettability distribution in a reservoir and updating the relative permeability curves based on its temperature propagation. The impact of the latter is studied in relation to the solubility of CO₂ injected into an aquifer using the numerical methods (i.e. ECLIPSE). If the CO₂ injected has a temperature higher than the formation geothermal temperature, it can change the wettability of the formation further to a more CO₂ wet condition. This increases the risk of leakage and also changes the relative permeability curves as the CO₂ moves through the reservoir, a situation that needs to be considered in reservoir simulations. The results show that updating and modifying the relative permeability curves with temperature variation in an aquifer can increase the amount of CO₂ dissolution there.

Wettability of rock/CO2/brine and rock/oil/CO2-enriched-brine systems:Critical parametric analysis and future outlook

CO₂ geo-sequestration is a promising technology to permanently store CO₂ in geological formations to control the atmospheric carbon footprint. In addition, CO₂ is frequently utilized in enhanced oil recovery operations to accelerate oil production. Both, CO₂ geo-storage and EOR, are significantly influenced by the wettability of the associated rock/CO₂/brine systems. Wettability drives the multiphase flow dynamics, and microscopic fluid distribution in the reservoir. Furthermore, while wettability is known to be influenced by varying in-situ conditions and surface chemistry of the rock/mineral, the current state-of-the-art indicates wider variabilities of the wetting states. This article, therefore, critically reviews the published datasets on CO₂ wettability of geological formations. Essentially, the rock/CO₂/brine and rock/crude-oil/CO₂-enriched-brine contact angle datasets for the important reservoir rocks (i.e. sandstone and carbonate rocks), as well as for the key minerals quartz and calcite are considered. Also, the parameters that influence wettability are critically analyzed, and the associated parametric trends are discussed and summarized. Finally, we identify pertinent research gaps and define the outlook of future research. The review, therefore, establishes a repository of the recent contact angle data, which thus assists to enhance our current understanding of the subject.

Impact of nanoparticles on the CO2-brine interfacial tension at high pressure and temperature

HYPOTHESIS

Nanofluid flooding has been identified as a promising method for enhanced oil recovery (EOR) and improved Carbon geo-sequestration (CGS). However, it is unclear how nanoparticles (NPs) influence the CO₂-brine interfacial tension (γ), which is a key parameter in pore-to reservoirs-scale fluid dynamics, and consequently project success. The effects of pressure, temperature, salinity, and NPs concentration on CO₂-silica (hydrophilic or hydrophobic) nanofluid γ was thus systematically investigated to understand the influence of nanofluid flooding on CO₂ geo-storage.

EXPERIMENTS

Pendant drop method was used to measure CO₂/nanofluid γ at carbon storage conditions using high pressure-high temperature optical cell.

FINDINGS

CO₂/nanofluid γ was increased with temperature and decreased with increased pressure which is consistent with CO₂/water γ. The hydrophilicity of NPs was the major factor; hydrophobic silica NPs significantly reduced γ at all investigated pressures and temperatures while hydrophilic NPs showed only minor influence on γ. Further, increased salinity which increased γ can also eliminate the influence of NPs on CO₂/nanofluid γ. Hence, CO₂/brine γ has low, but, reasonable values (higher than 20 mN/m) at carbon storage conditions even with the presence of hydrophilic NPs, therefore, CO₂ storage can be considered in oil reservoirs after flooding with hydrophilic nanofluid. The findings of this study provide new insights into nanofluids applications for enhanced oil recovery and carbon geosequestration projects.

High pressure-elevated temperature x-ray micro-computed tomography for subsurface applications

Physical, chemical and mechanical pore-scale (i.e. micrometer-scale) mechanisms in rock are of key importance in many, if not all, subsurface processes. These processes are highly relevant in various applications, e.g. hydrocarbon recovery, CO₂ geo-sequestration, geophysical exploration, water production, geothermal energy production, or the prediction of the location of valuable hydrothermal deposits. Typical examples are multi-phase flow (e.g. oil and water) displacements driven by buoyancy, viscous or capillary forces, mineral-fluid interactions (e.g. mineral dissolution and/or precipitation over geological times), geo-mechanical rock behaviour (e.g. rock compaction during diagenesis) or fines migration during water production, which can dramatically reduce reservoir permeability (and thus reservoir performance). All above examples are 3D processes, and 2D experiments (as traditionally done for micro-scale investigations) will thus only provide qualitative information; for instance the percolation threshold is much lower in 3D than in 2D. However, with the advent of x-ray micro-computed tomography (μCT) - which is now routinely used - this limitation has been overcome, and such pore-scale processes can be observed in 3D at micrometer-scale. A serious complication is, however, the fact that in the subsurface high pressures and elevated temperatures (HPET) prevail, due to the hydrostatic and geothermal gradients imposed upon it. Such HPET-reservoir conditions significantly change the above mentioned physical and chemical processes, e.g. gas density is much higher at high pressure, which strongly affects buoyancy and wettability and thus gas distributions in the subsurface; or chemical reactions are significantly accelerated at increased temperature, strongly affecting fluid-rock interactions and thus diagenesis and deposition of valuable minerals. It is thus necessary to apply HPET conditions to the aforementioned μCT experiments, to be able to mimic subsurface conditions in a realistic way, and thus to obtain reliable results, which are vital input parameters required for building accurate larger-scale reservoir models which can predict the overall reservoir-scale (hectometer-scale) processes (e.g. oil production or diagenesis of a formation). We thus describe here the basic workflow of such HPET-μCT experiments, equipment requirements and apparatus design; and review the literature where such HPET-μCT experiments were used and which phenomena were investigated (these include: CO₂ geo-sequestration, oil recovery, gas hydrate formation, hydrothermal deposition/reactive flow). One aim of this paper is to give a guideline to users how to set-up a HPET-μCT experiment, and to provide a quick overview in terms of what is possible and what not, at least up to date. As a conclusion, HPET-μCT is a valuable tool when it comes to the investigation of subsurface micrometer-scaled processes, and we expect a rapidly expanding usage of HPET-μCT in subsurface engineering and the subsurface sciences.

Modeling CO2-Water-Mineral Wettability and Mineralization for Carbon Geosequestration

Carbon dioxide (CO₂) capture and storage (CCS) is an important climate change mitigation option along with improved energy efficiency, renewable energy, and nuclear energy. CO₂ geosequestration, that is, to store CO₂ under the subsurface of Earth, is feasible because the world's sedimentary basins have high capacity and are often located in the same region of the world as emission sources. How CO₂ interacts with the connate water and minerals is the focus of this Account. There are four trapping mechanisms that keep CO₂ in the pores of subsurface rocks: (1) structural trapping, (2) residual trapping, (3) dissolution trapping, and (4) mineral trapping. The first two are dominated by capillary action, where wettability controls CO₂ and water two-phase flow in porous media. We review state-of-the-art studies on CO₂/water/mineral wettability, which was found to depend on pressure and temperature conditions, salt concentration in aqueous solutions, mineral surface chemistry, and geometry. We then review some recent advances in mineral trapping. First, we show that it is possible to reproduce the CO₂/water/mineral wettability at a wide range of pressures using molecular dynamics (MD) simulations. As the pressure increases, CO₂ gas transforms into a supercritical fluid or liquid at ∼7.4 MPa depending on the environmental temperature. This transition leads to a substantial decrease of the interfacial tension between CO₂ and reservoir brine (or pure water). However, the wettability of CO₂/water/rock systems depends on the type of rock surface. Recently, we investigated the contact angle of CO₂/water/silica systems with two different silica surfaces using MD simulations. We found that contact angle increased with pressure for the hydrophobic (siloxane) surface while it was almost constant for the hydrophilic (silanol) surface, in excellent agreement with experimental observations. Furthermore, we found that the CO₂ thin films at the CO₂-hydrophilic silica and CO₂-H₂O interfaces displayed a linear correlation, which can in turn explain the constant contact angle on the hydrophilic silica surface. In view of the literature and our study results, a few recommendations seem necessary to construct a molecular system suitable to study wettability with MD simulations. Future work should be conducted to determine the influence of brine salinity on the wettability of minerals with high cation exchange capacity. Mineral trapping is believed to be an extremely slow process, likely taking thousands of years. However, a recent pilot study demonstrated that CO₂ mineralization occurs within 2 years in highly reactive basalt reservoirs. A first-principles MD study has also shown that carbonation reactions occur rapidly at the surface oxygen sites of a reactive mineral. We observed carbonate ions on both a newly cleaved quartz surface (without hydrolysis), and a basalt andesine surface after hydrolysis in a CO₂-rich environment. Future work should consider the influence of water, gas impurities, and mineral cation type on carbonation.

CO2-Water-Rock Wettability: Variability, Influencing Factors, and Implications for CO2 Geostorage

Carbon geosequestration (CGS) has been identified as a key technology to reduce anthropogenic greenhouse gas emissions and thus significantly mitigate climate change. In CGS, CO₂ is captured from large point-source emitters (e.g., coal fired power stations), purified, and injected deep underground into geological formations for disposal. However, the CO₂ has a lower density than the resident formation brine and thus migrates upward due to buoyancy forces. To prevent the CO₂ from leaking back to the surface, four trapping mechanisms are used: (1) structural trapping (where a tight caprock acts as a seal barrier through which the CO₂ cannot percolate), (2) residual trapping (where the CO₂ plume is split into many micrometer-sized bubbles, which are immobilized by capillary forces in the pore network of the rock), (3) dissolution trapping (where CO₂ dissolves in the formation brine and sinks deep into the reservoir due to a slight increase in brine density), and (4) mineral trapping (where the CO₂ introduced into the subsurface chemically reacts with the formation brine or reservoir rock or both to form solid precipitates). The efficiency of these trapping mechanisms and the movement of CO₂ through the rock are strongly influenced by the CO₂-brine-rock wettability (mainly due to the small capillary-like pores in the rock which form a complex network), and it is thus of key importance to rigorously understand CO₂-wettability. In this context, a substantial number of experiments have been conducted from which several conclusions can be drawn: of prime importance is the rock surface chemistry, and hydrophilic surfaces are water-wet while hydrophobic surfaces are CO₂-wet. Note that CO₂-wet surfaces dramatically reduce CO₂ storage capacities. Furthermore, increasing pressure, salinity, or dissolved ion valency increases CO₂-wettability, while the effect of temperature is not well understood. Indeed theoretical understanding of CO₂-wettability and the ability to quantitatively predict it are currently limited although recent advances have been made. Moreover, data for real storage rock and real injection gas (which contains impurities) is scarce and it is an open question how realistic subsurface conditions can be reproduced in laboratory experiments. In conclusion, however, it is clear that in principal CO₂-wettability can vary drastically from completely water-wet to almost completely CO₂-wet, and this possible variation introduces a large uncertainty into trapping capacity and containment security predictions.

Pore Scale Observations of Trapped CO2 in Mixed-Wet Carbonate Rock: Applications to Storage in Oil Fields

Geologic CO2 storage has been identified as a key to avoiding dangerous climate change. Storage in oil reservoirs dominates the portfolio of existing projects due to favorable economics. However, in an earlier related work ( Al-Menhali and Krevor Environ. Sci. Technol. 2016 , 50 , 2727 - 2734 ) , it was identified that an important trapping mechanism, residual trapping, is weakened in rocks with a mixed wetting state typical of oil reservoirs. We investigated the physical basis of this weakened trapping using pore scale observations of supercritical CO2 in mixed-wet carbonates. The wetting alteration induced by oil provided CO2-wet surfaces that served as conduits to flow. In situ measurements of contact angles showed that CO2 varied from nonwetting to wetting throughout the pore space, with contact angles ranging 25° < θ < 127°; in contrast, an inert gas, N2, was nonwetting with a smaller range of contact angle 24° < θ < 68°. Observations of trapped ganglia morphology showed that this wettability allowed CO2 to create large, connected, ganglia by inhabiting small pores in mixed-wet rocks. The connected ganglia persisted after three pore volumes of brine injection, facilitating the desaturation that leads to decreased trapping relative to water-wet systems.