CO2-brine Systems Research Articles

Compositional Simulation for Carbon Storage in Porous Media Using an Electrolyte Association Equation of State

Summary We present a new algorithm based on automatic differentiation that enables precise computation of the derivatives of the Z-factor, facilitating the utilization of Newton’s method or coupling with a robust flow solver. Leveraging a free open-source code [MATLAB Reservoir Simulation Toolbox (MRST)], we develop an electrolyte cubic plus association (e-CPA) equation of state (EoS) model to accurately represent the injection of carbon dioxide (CO2) in brine. By integrating flow and thermodynamics, we construct an advanced compositional simulator using MRST’s object-oriented, automatic differentiation framework and the newly developed e-CPA EoS model. This simulator offers flexibility through both overall-composition and natural-variable formulations, achieved by selecting different primary variables. The Péneloux volume translation technique is employed to modify the EoS model’s volume, ensuring accurate density calculation for the mixture. Additionally, we introduce a viscosity model, e-CPA-FV, which accurately predicts the viscosity of carbon capture and storage (CCS) fluids, surpassing the accuracy of the traditional Lohrenz-Bray-Clark (LBC) model. Our simulator demonstrates superior performance in predicting CO2-brine systems compared with the standard formulation based on the Peng-Robinson (PR) EoS and can handle brine with various salts. The self-contained source code necessary to reproduce all examples is available on the open-access Zenodo digital repository (doi: 10.5281/zenodo.10691505).

Toward Predicting Interfacial Tension of Impure and Pure CO2-Brine Systems Using Robust Correlative Approaches.

In the context of global climate change, significant attention is being directed toward renewable energy and the pivotal role of carbon capture and storage (CCS) technologies. These innovations involve secure CO2 storage in deep saline aquifers through structural and capillary processes, with the interfacial tension (IFT) of the CO2-brine system influencing the storage capacity of formations. In this study, an extensive data set of 2811 experimental data points was compiled to model the IFT of impure and pure CO2-brine systems. Three white-box machine learning (ML) methods, namely, genetic programming (GP), gene expression programming (GEP), and group method of data handling (GMDH) were employed to establish accurate mathematical correlations. Notably, the study utilized two distinct modeling approaches: one focused on impurity compositions and the other incorporating a pseudocritical temperature variable (Tcm) offering a versatile predictive tool suitable for various gas mixtures. Among the correlation methods explored, GMDH, employing five inputs, exhibited exceptional accuracy and reliability across all metrics. Its mean absolute percentage error (MAPE) values for testing, training, and complete data sets stood at 7.63, 7.31, and 7.38%, respectively. In the case of six-input models, the GEP correlation displayed the highest precision, with MAPE values of 9.30, 8.06, and 8.31% for the testing, training, and total data sets, respectively. The sensitivity and trend analyses revealed that pressure exerted the most significant impact on the IFT of CO2-brine, showcasing an adverse effect. Moreover, an impurity possessing a critical temperature below that of CO2 resulted in an elevated IFT. Consequently, this relationship leads to higher impurity concentrations aligning with lower Tcm values and subsequently elevated IFT. Also, monovalent and divalent cation molalities exhibited a growing influence on the IFT, with divalent cations exerting approximately double the influence of monovalent cations. Finally, the Leverage approach confirmed both the reliability of the experimental data and the robust statistical validity of the best correlations established in this study.

Wettability alterations of amorphous shales in geological carbon storage: Impact of acidic conditions in deep saline aquifers

The feasibility of Geological carbon storage (GCS) in deep saline aquifers is mainly determined by its ability to prevent CO2 leakage through caprock, which is most commonly shale. The wettability of the shale–CO2–brine system is one of the most essential petro-physical parameters in the assessment of the integrity of shale caprock. Current literature suggests that wettability measurements of the shale–CO2–brine system have many contradictory outcomes. Furthermore, previous applications of molecular dynamic simulation (MDS) to estimate wettability of the shale–CO2–brine system disregarded variations in shale composition and concentrated on just a single component. Moreover, there has been limited investigation into the effect of CO2 dissolution in brine and the resultant acidic conditions on the wettability of the shale–CO2–brine combination. In this study, MDS is implemented for evaluating the wettability of a system made up of amorphous shale, CO2, and brine under conditions representative of typical geological storage site. An amorphous shale molecular model has been developed through the integration of illite, quartz, and kerogen. The microscopic wetting and half-angle fitting approaches have been applied to establish the wettability. A qualitative investigation was also conducted to further examine the wettability of the studied systems. Additionally, a contrasting analysis was conducted to assess the conclusions of this study in relation to relevant literature data. The findings of this study demonstrate the wettability of an amorphous shale–CO2–brine system is significantly influenced by the composition of the shale and the presence of acidic conditions. The water contact angles for shales with TOC values of 5% and 10% were measured to be 42.1° and 52.5°, respectively, at a pressure of 10 MPa and a temperature of 333 K, without taking into account any acidic conditions. The addition of induced acidic conditions resulted in a 15% and 24% increase in the water contact angle, respectively, for high and low TOC shale systems, respectively. The findings of this study have significant implications on the containment of stored CO2, thereby contributing to the worldwide efforts of minimizing greenhouse gas emissions through enhancements in the performance of GCS processes.

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).

Solubility and interfacial tension models for CO2–brine systems under CO2 geological storage conditions

Thermodynamic properties of the CO2–brine pseudo-binary system are essential for the design of geological carbon storage (GCS) projects, especially those utilizing saline aquifers. The gas–liquid–solid interactions manifest in the interfacial tensions (IFTs) and contact angle determine the injectability, sealing capacity, and storage security of the GCS process. Dissolution of CO2 in the reservoir brine occurs throughout the entire GCS process, leading to enhanced storage capacity but also to acidification of the brine, possibly leading to reservoir or seal damage. Two of the most important thermodynamic properties of the fluids are the mutual solubility and the IFT of the CO2–brine pseudo-binary system. In this work, we report a new correlative model for the IFT between CO2- and water-rich phases over wide ranges of temperature (273 to 473 K) and pressure (up to 100 MPa). The model is parameterized for brines comprising any combinations of sodium, potassium, calcium and magnesium cations with chloride, sulphate and bicarbonate anions up to a total molality of at least 5 mol·kg−1. The independent variables in this new model are reduced temperature, ion molalities and the mole fraction of CO2 dissolved in the aqueous phase. The latter is related to temperature, pressure and ion molalities by an improved model for the mutual solubility. More than 2000 experimental data points were used in the development of the two models. For the IFT of the CO2-H2O binary system, the overall root-mean-square deviation (RMSD) is 0.65mN·m−1 while the absolute average relative deviation (AARD) is 1.8%. In the case of mutual solubility, the RMSD of CO2 mole fraction in the aqueous phase is 0.0003 and the AARD is 5.5% while, in the non-aqueous phase, the RMSD of H2O mole fraction is 0.0035 and the corresponding AARD is 8.7%. Similar results are found for the CO2-brine systems.

Dissolution-driven convection of low solubility fluids in porous media

Geological sequestration represents a promising strategy for storing CO2. In order to further elucidate this process, we simulated the dissolution-driven convection of a CO2-brine system with a free interface in a porous medium, based on a novel Darcy-Cahn-Hilliard model that accounts for the low solubility of CO2 with brine. We consider a range of unstable Rayleigh numbers Ra, and we derive a quantitative relationship for the dimensionless solute flux. This flux exhibits distinctly different behaviors during the various stages of the flow. In particular, during the free convection stage, larger Ra-values result in a moderate decrease of the solute flux, while the solute flux is approximately independent of Ra during the constant flux stage. In order to evaluate the solute flux during the shutdown stage, we employ simulations in the two-sided Rayleigh-Bénard cell configuration. With a correction factor a=0.67 to account for the damping effect of the bottom boundary, the model can reproduce the solute flux during the shutdown stage. By accounting for the effects of partial miscibility, the simulation approach developed here holds the potential to yield more accurate estimates of the solute flux in the context of CO2 sequestration and related applications.

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).

CO2 hydrate formation in NaCl systems and undersaturated aqueous solutions

A high-pressure experimental setup was used to obtain experimental data on the Hydrate Equilibrium (melting) Temperature (HET) of aqueous phases undersaturated with CO2, at different CO2 saturation levels and with different aqueous phase compositions (sodium chloride and sodium chloride/calcium chloride). This paper details the experimental equipment, methods, test fluids, and results. To study the phase equilibria of CO2-brine systems and further validate the results, hydrate dissociation conditions of CO2 in different concentrations of NaCl aqueous solutions were measured in the low-temperature region and over a wide range of pressure. Experimental results were compared against predictions of the simplified Cubic Plus Association Equation of State (sCPA-EoS) coupled with the van der Waals and Platteeuw solid solution theory.

Simultaneous Prediction of Equilibrium, Interfacial, and Transport Properties of CO2-Brine Systems Using Molecular Dynamics Simulation: Applications to CO2 Storage

This study aims to provide accurate simultaneous predictions of crucial properties affecting CO2 storage in saline aquifers with deep microstructural insights using comprehensive molecular dynamics (MD) simulations under actual operating conditions ranges. We investigated the effects of pressure, temperature, and salinity on mutual solubility, interfacial tension (IFT), density, and viscosity of a CO2-brine system over the temperature range of 323.15–393.15 K, pressures up to 30 MPa, and salinity range of 0.98–2.97 mol/kg. Brine was resembled by employing different brine systems like actual reservoirs, including mixed electrolyte solutions containing monovalent and divalent ions. MD model configurations and force fields were validated by experimental data of a CO2-water/NaCl aqueous solution. The maximum average absolute deviations for the solubility, density, and IFT were 5.50, 6.95, and 7.136%, respectively. The simulation results indicated that mutual solubilities of CO2 and water in the CO2-NaCl + KCl solution system are higher than those of CO2-NaCl + CaCl2, while for IFT, the opposite trend is observed. Unlike pressure, salt concentration variations result in considerable density and viscosity changes for all systems. The maximum density and viscosity values are obtained for the brine-containing divalent cations. This study gives insight into the storage process and relates the microstructure effects to solubility, IFT, and viscosity of CO2-brine systems using a single MD model.

Effect of organic acids on CO2-rock and water-rock interfacial tension: Implications for CO2 geo-storage

A small concentration of organic acid in carbon dioxide (CO2) storage formations and caprocks could significantly alter the wettability of such formations into less water-wet conditions, decreasing the CO2-storage potential and containment security. Recent studies have attempted to infer the influence of the organic acid concentration on the wettability of rock–CO2–brine systems by measuring advancing and receding contact angles. However, no studies have investigated the influence of organic acid contamination on CO2-storage capacities from rock-fluid interfacial tension (IFT) data because solid-brine and solid-CO2 IFT values cannot be experimentally measured. Equilibrium contact angles and rock-fluid IFT datasets were used to evaluate the viability of CO2 storage in storage rocks and caprocks. First, the contact angles of rock in brine-CO2 systems were measured to compute Young's equilibrium contact angles. Subsequently, rock-brine and rock-gas IFT values at CO2 geo-storage conditions were computed via a modified form of Neumann's equation of state. For two storage-rock minerals (quartz and calcite) and one caprock mineral (mica), the results demonstrated high CO2-brine equilibrium contact angles at high pressure (0.1–25 MPa) and increasing concentrations of stearic acid (10−5 to 10−2 mol/L). Rock-brine IFT increased with the increased stearic acid concentration but remained constant with increased pressure. In all conditions, the order of increasing hydrophobicity of the mineral surfaces is calcite > mica > quartz. At 323 K, 25 MPa, and a stearic acid concentration of 10−2 mol/L, quartz became intermediate-wet with a CO2-brine equilibrium contact angle of 89.8°, whereas mica and calcite became CO2-wet with CO2-brine equilibrium contact angles of 117.5° and 136.5°, respectively. This work provides insight into the effects of organic acids inherent in CO2 geo-storage formations and caprocks on rock wettability and rock-fluid interfacial interactions.

Application of robust intelligent schemes for accurate modelling interfacial tension of CO2 brine systems: Implications for structural CO2 trapping

Given the current global climate change, renewable energy sources, carbon capture, utilization, and storage (CCUS) are being considered as a potential solutions to this critical global issue. Structural and capillary processes can be used to store carbon dioxide (CO2) in deep saline aquifers in a way that is safe and does not harm the environment. Due to this fact, the interfacial tension (IFT) of the CO2-brine system is an important factor influencing the capacity of storage formations to sequester CO2. As a result, IFT is essential for conducting a thorough and accurate evaluation in order to determine the optimal strategy for CO2 storage projects. This paper used intelligent models such as Gaussian Process Regression (GPR), Radial Basis Function (RBF), and Random Forest (RF) to forecast IFT in the CO2-brine system with high precision and substantial time saving. The results reveal that the constructed RF model could deliver excellent performance in predicting IFT with the lowest average absolute percent relative error (AAPRE = 1.9156 percent), highest coefficient of determination (R2 = 0.9907), and lowest root mean squared error (RMSE = 0.7279). Furthermore, a sensitivity analysis was performed to ascertain the most critical parameters in the RF model to be considered. The parametric analysis found that both pure and non-pure CO2 systems had a significant impact on IFT prediction.Also, the RF model was used to assess the structural trapping capacity of a storage location in the Cuu Long Basin. The estimation results obtained in this study agreed perfectly with the previous ones. The findings of this study can aid in a better understanding of how machine learning models can be applied to predict IFT values for the evaluation of the structural CO2 storage capacity.

New correlations for interfacial tension of CO2-water-electrolyte systems at high pressure

The CO2-aqueous phase interfacial tension (IFT) is a major property in enhanced oil recovery (EOR) processes by low salinity water alternating CO2 (CO2LSWAG) flooding. It affects oil displacement in CO2LSWAG processes as it is related to CO2 dissolution in oil through the CO2-saturated aqueous phase. Therefore, low CO2-aqueous phase IFT values are related to improvements in the oil recovery. However, the literature is still absent of simple and accurate models for IFT of CO2-water-electrolyte systems at reservoir temperature, water salinity and high pressure. Aiming to fill this gap, this work employed IFT data from the literature to present novel empirical and semiempirical correlations to calculate the IFT of these systems as a function of the phase densities at reservoir conditions, including the atypical conditions of high pressure and salinity of Brazilian Pre-Salt basin. The strategies proposed to model the phase densities when modeling the IFT through empirical and semiempirical equations are unprecedented in the literature and produced quite promising results. The results indicate that the proposed empirical equations can predict the CO2-water IFT with overall absolute deviations up to 6% over pressures between 0.1 and 45 MPa and temperatures between 30 and 75 °C. For CO2-brine systems, the proposed semiempirical equation provided an overall absolute deviation lower than 8% for brines composed of only NaCl, both NaCl and CaCl2 and only CaCl2 over 2 to 45 MPa, 40 to 75.5 °C and salinities up to 356,872 ppm. The accuracy of the proposed correlations is higher than those of the Parachor model, usually employed in commercial reservoir simulators. Also, they need lower computational efforts and can be advantageous for simulations purposes.

CO2 – brine – sandstone wettability evaluation at reservoir conditions via Nuclear Magnetic Resonance measurements

CO2-rock wettability is a key parameter which governs CO2 trapping capacities and containment security in the context of CO2 geo-sequestration schemes. However, significant uncertainties still exist in terms of predicting CO2 rock wettability at true reservoir conditions. This study thus reports on wettability measurements via independent Nuclear Magnetic Resonance (NMR) experiments on sandstone (CO2–brine systems) to quantify Wettability Indices (WI) using the United States Bureau of Mines (USBM) scale. The results show that CO2 (either molecularly dissolved or as a separate supercritical phase) significantly reduced the hydrophilicity of the sandstone from strongly water-wet (WI ≈ 1) to weakly water-wet (WI = 0.26), and associated with that the water-wetness of the rock for the two-phase systems. This was caused by additional protonation of surface silanol groups on the quartz, induced by carbonic acid. Capillary pressure and relative permeability curves and residual CO2 saturation were also measured; these results were compared with literature data, and general consistency was found. NMR T2 distribution measurements also demonstrated preferential water displacement in large pores (r > 1 µm) following scCO2 flooding, while no change was observed for smaller pores (r < 1 µm). These insights add confidence to the assessments of CO2-rock wettability and therefore reduce project risk. This work thus aids in the implementation of large-scale CO2 sequestration.

Modelling of the Phase-Partitioning Behaviors for CO2-Brine System at Geological Conditions

Abstract An improved phase-partitioning model is proposed for the prediction of the mutual solubility in the CO2-brine system containing Na+, K+, Ca2+, Mg2+, Cl-, and SO42-. The correlations are computationally efficient and reliable, and they are primarily designed for incorporation into a multiphase flow simulator for geology- and energy-related applications including CO2 sequestration, CO2-enhanced geothermal systems, and CO2-enhanced oil recovery. The model relies on the fugacity coefficient in the CO2-rich phase and the activity coefficient in the aqueous phase to estimate the phase-partitioning properties. In the model, (i) the fugacity coefficients are simulated by a modified Peng-Robinson equation of state which incorporates a new alpha function and binary interaction parameter (BIP) correlation; (ii) the activity coefficient is estimated by a unified equilibrium constant model and a modified Margules expression; and (iii) the simultaneous effects of salting-out on the compositions of the CO2-rich phase and the aqueous phase are corrected by a Pizter interaction model. Validation of the model calculations against literature experimental data and traditional models indicates that the proposed model is capable of predicting the phase-partitioning behaviors in the CO2-brine system with a higher accuracy at temperatures of up to 623.15 K and pressures of up to 350 MPa. Using the proposed model, the phase diagram of the CO2+H2O system is generated. An abrupt change in phase compositions is revealed during the transfer of the CO2-rich phase from vapor to liquid or supercritical. Furthermore, the preliminary simulation shows that the salting-out effect can considerably decrease the water content in the CO2-rich phase, which has not been well experimentally studied so far.

Identifying two-phase flow rock types in CO2-brine systems using TEM-function

CO2 injection into deep saline aquifers is a feasible solution for mitigating climate change. Prediction of fate and transport of CO2 in subsurface requires accurate numerical reservoir models. A reliable reservoir model needs a precise two-phase flow characterization. Recently, technique of True Effective Mobility (TEM-function) was proposed to characterize multi-phase fluid flow properties of rocks (i.e., dynamic rock typing). In this study, applicability of two-phase flow rock typing in CO2-brine systems was studied using TEM-function. Five and three two-phase flow rock types were found for the studied sandstone and carbonate samples, respectively. Existence of multiple dynamic rock types shows that the injection of CO2 into saline aquifers forms a complex and heterogeneous two-phase flow pattern due to pore space heterogeneity and fluid properties along with in-situ conditions. Relative permeability curves of each two-phase rock type were also studied to check if relative permeability data can reflect two-phase flow characteristics. It was observed that relative permeability fails in establishing a relationship with two-phase flow characteristics in the CO2-brine systems. Furthermore, it was investigated whether the two-phase flow rock types identified by TEM-function establish a relationship with basic rock properties. The results show that the two-phase flow rock types identified by TEM-function establish clear relationships with FZI* (FZI-star).

Numerical investigations of foam-assisted CO2 storage in saline aquifers

CO2-foam injection is a promising technology for reducing gas mobility and increasing trapping within the swept region in deep brine aquifers. In this work, a consistent thermodynamic model based on a combination of the Peng-Robinson equation of state (PR EOS) for gas components with an activity model for the aqueous phase is implemented to accurately describe the complex phase-behavior of the CO2-brine system. The phase-behavior module is combined with the representation of foam by an implicit-texture (IT) model with two flow regimes. This combination can accurately capture the complicated dynamics of miscible CO2 foam at various stages of the sequestration process. The Operator-Based Linearization (OBL) approach is applied to improve the efficiency of the highly nonlinear CO2-foam problem by transforming the discretized nonlinear conservation equations into a quasi-linear form based on state-dependent operators. We first validate our simulation results for enhanced CO2 dissolution in a small domain with and without the presence of a capillary transition zone (CTZ). Then a 3D unstructured reservoir is used to examine CO2-foam behavior and its effects on CO2 storage. Simulation studies show good agreement with analytical solutions in both cases with and without CTZ. Besides, the presence of a CTZ enhances the CO2 dissolution rate in brine. Foam simulations show that foams can reduce gas mobility effectively by trapping gas bubbles and inhibit CO2 from migrating upward in the presence of gravity, which in turn improves the sweep efficiency and opens the unswept region for CO2 storage. In the long run (post-injection), with the increasing effects of dissolution, the mechanism of residual trapping, due to the presence of foam, may not be significant. This work suggests a possible strategy to develop an efficient CO2 storage technology.

A simple model for the prediction of mutual solubility in CO2-brine system at geological conditions

Reliable and accurate prediction of phase-partitioning behaviors in CO2-Brine system over a wide range of temperature, pressure and ionic composition (T–P–msalts) is of fundamental and practical importance to many geological-, energy-, and environmental-related technical applications. In this work, a simple model for the prediction of mutual solubility in the systems of CO2 + H2O and CO2 + Brine containing Na+, K+, Ca2+, Mg2+, Cl−, and SO42− is proposed, which can cover the typical geological conditions (0–250 °C, 0–200 MPa). Validation of the model calculations against updated experimental data available indicates that the simulation errors for CO2 solubility in pure water and brine are 6.899% and 8.08%, respectively, whereas the simulation error for water content in the CO2 rich phase is 9.67%. Compared to conventional complicated models, the proposed model is capable of simultaneously predicting CO2 solubility in aqueous phase and water content in CO2 rich phase, and obtains a comparable accuracy over a large T–P–msalts scale. The simulation results demonstrate that the developed model can reproduce the abrupt variations in phase compositions during the phase transition of the CO2 rich phase, and describe the influence of different ions on CO2 solubility. More importantly, the model is explicit, derivative-continuous and does not require iterative algorithms for its use, which means that it is computationally efficient and reliable to be incorporated into a large-scale multiphase flow simulator in geological processes.

Fault seal modelling – the influence of fluid properties on fault sealing capacity in hydrocarbon and CO 2 systems

Fault seal analysis is a key part of understanding the hydrocarbon trapping mechanisms in the petroleum industry. Fault seal research has also been expanded to CO 2 –brine systems for the application to carbon capture and storage (CCS). The wetting properties of rock-forming minerals in the presence of hydrocarbons or CO 2 are a source of uncertainty in the calculations of capillary threshold pressure, which defines the fault sealing capacity. Here, we explore this uncertainty in a comparison study between two fault-sealed fields located in the Otway Basin, SE Australia. The Katnook Field in the Penola Trough is a methane field, while Boggy Creek in Port Campbell contains a high-CO 2 –methane mixture. Two industry standard fault seal modelling methods, one based on laboratory measurements of fault samples and the other based on a calibration of a global dataset of known sealing faults, are used to discuss their relative strengths and applicability to the CO 2 storage context. We identify a range of interfacial tensions and contact angle values in the hydrocarbon–water system under the conditions assumed by the second method. Based on this, the uncertainty related to the spread in fluid properties was determined to be 24% of the calculated threshold capillary pressure value. We propose a methodology of threshold capillary pressure conversion from hydrocarbons–brine to the CO 2 –brine system, using an input of appropriate interfacial tension and contact angle under reservoir conditions. The method can be used for any fluid system where fluid properties are defined by these two parameters. Supplementary material: (1) Fault seal modelling methods and calculations, and (2) hydrocarbon and CO 2 interfacial tensions and contact angle values collected in the literature are available at https://doi.org/10.6084/m9.figshare.c.4877049 This article is part of the Energy Geoscience Series available at https://www.lyellcollection.org/cc/energy-geoscience-series

Data-driven modeling of interfacial tension in impure CO2-brine systems with implications for geological carbon storage

Global climate change is a pressing problem, and given the current state of development of renewable energies, Carbon Capture and Storage (CCS) appears a promising solution. Deep saline aquifers are the most accessible geological locations for safe CO2 sequestration, where CO2 can be securely trapped mostly by structural and capillary trapping mechanisms. The efficiency of both mechanisms is governed by multiphase flow characteristics that are heavily dependent on interfacial tension (IFT) between the gaseous and aqueous phases. In this study, we conduct a comprehensive data-driven study on the interfacial tension of pure and impure gas-brine mixtures within saline aquifers. We carefully collect 2517 experimental data, upon which we develop seven machine-learning based models for predicting the IFT. These include, namely, four differently optimized multilayer perceptron models, a radial basis function neural network, a least squares support vector machine, and a group method of data handling-type neural network. The three most accurate intelligent models are subsequently incorporated into a state-of-the-art committee machine intelligent system. We use a pseudo (average) critical temperature variable to capture the gas phase impurities while developing a general-in-purpose predictive tool for any gas mixture. We comprehensively evaluate the accuracy and statistical validity of our models, and demonstrate their robustness relative to major empirical correlations currently in use. The analyses reveal the non-trivial behavior of IFT against various parameters. Finally, we elucidate the impact of gas and brine impurities on the storage capacity of saline aquifers at various in-situ conditions.

Evolution of hysteresis relative permeability of wetting brine phase using contact angle hysteresis in a partially saturated CO2-brine system

ABSTRACT In sequestration of CO2 in deep saline aquifers, the relative permeability of the immiscible fluids plays a crucial role in governing dissolution and capillary trapping mechanisms. Relative permeability is solely dependent on capillary pressure and saturation at that instant of time, whereas the capillary pressure dynamically changes during flow reversal resulting in the hysteresis behavior of the relative permeability curves. However, the conventionally used models equate relative permeability as an explicit function of saturation, neglecting the inherent physics that govern the immiscible displacement of fluids. On the other hand, upscaling the pore scale mechanisms, such as contact angle hysteresis and wettability characteristics, to Darcy scale remains complicated. In the present investigation, an attempt has been made in formulating a methodology to compute relative permeability of the phase fluids based on contact angle hysteresis. The relative permeability curves calculated using the present model have been compared with that computed using existing methodology present in the literature. It has been observed that the present relative permeability model effectively calculates the drainage and imbibition relative permeability of both the wetting and non-wetting phases in the porous system.