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1. Fracture Characteristics of Shale: Unraveling CO2-Driven Mechanical Metamorphosis at Microscale

   https://doi.org/10.56952/ARMA-2024-0162  

   Mahgoub, S A; Abedi, S (June 2024, ARMA)

   ABSTRACT:This study investigates the distinction between unreacted shale samples and those exposed to CO2-rich brine under elevated temperature (100°C) and pressure (1800 psi) conditions over 28 days. Samples underwent scratch testing under constant loading to ensure independent penetration depth, circumventing variability associated with load-dependent outcomes prevalent in progressive loading methodologies. Vertical hardness profiles revealed significant variations between reacted and unreacted regions, influenced by differential dissolution and precipitation characteristics, while horizontal hardness provided limited insights, particularly in the reacted region where higher tangential forces and deeper scratches indicated greater material compressibility. Distinct scratch path variations were observed, with fractures absent in the ductile reacted region at lower testing forces. The shale samples were sourced from the Eagle Ford Formation, providing insights into the mechanical response of carbonate-rich shale rocks in extreme environments. This research enhances understanding of shale's mechanical properties and material responses under diverse operational conditions, elucidating interactions with influential environmental factors, particularly in CO2-exposed scenarios. Conducted at a microscale level, this study offers detailed insights into material behavior, crucial for predicting long-term stability of geostructures exposed to reactive brine and potential CO2 leakage in subsurface reservoirs. 1. INTRODUCTIONThe investigation into chemical interactions between carbonate rocks and acidic brine is cruical for understanding complex mechanical and microstructural transformations essential for applications like geostructure stability, CO2 storage, and energy exploitation. Under elevated pressure and temperature conditions, the equilibrium between injected fluids and rocks undergoes alterations, leading to geochemical responses, especially with the presence of CO2 as a supercritical phase or in aqueous form (Prakash et al. 2023a; Prakash et al. 2022). In this context, investigating fracture properties becomes essential, aiming to comprehend the development and propagation of fractures within reacted formations to evaluate structural integrity and potential pathways for fluid migration.Prior geochemical investigations have explored the localized repercussions of CO2 attacks on rock permeability, shedding light on alterations attributed to carbonate precipitation sealing fractures and pores or the dissolution of diverse minerals (Burnside et al. 2013; Minardi et al. 2021). Shale rocks exposed to acidic brine predominantly undergo carbonate reactions, particularly carbonates dissolution and precipitation (Prakash et al., 2022; Prakash et al. 2023b). Experimental studies on fracture mechanics and mechanical properties have utilized conventional methods such as single edge notched bend, chevron notched beam, three-point bending, and semi-circular bending tests, acknowledging their inherent limitations (Smith & Chowdary, 1975; Bazant and Kazemi, 1990; Helmer et al. 2014; Dubey et al., 2020). 

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2. Persistent Homology as a Heterogeneity Metric for Predicting Pore Size Change in Dissolving Carbonates

   https://doi.org/10.1029/2023WR034559  

   Thompson, E. P.; Ellis, B. R. (September 2023, Water Resources Research)

   Abstract Accurate prediction of physical alterations in carbonate reservoirs under dissolution is critical for development of subsurface energy technologies. The impact of mineral dissolution on flow characteristics depends on the connectivity and tortuosity of the pore network. Persistent homology is a tool from algebraic topology that describes the size and connectivity of topological features. When applied to 3D X‐ray computed tomography (XCT) imagery of rock cores, it provides a novel metric of pore network heterogeneity. Prior works have demonstrated the efficacy of persistent homology in predicting flow properties in numerical simulations of flow through porous media. Its ability to combine size, spatial distribution, and connectivity information make it a promising tool for understanding reactive transport in complex pore networks, yet limited work has been done to apply persistence analysis to experimental studies on natural rocks. In this study, three limestone cores were imaged by XCT before and after acid‐driven dissolution flow‐through experiments. Each XCT scan was analyzed using persistent homology. In all three rocks, permeability increase was driven by the growth of large, connected pore bodies. The two most homogenous samples saw an increased effect nearer to the flow inlet, suggesting emerging preferential flow paths as the reaction front progresses. The most heterogeneous sample showed an increase in along‐core homogeneity during reaction. Variability of persistence showed moderate positive correlation with pore body size increase. Persistence heterogeneity analysis could be used to anticipate where greatest pore size evolution may occur in a reservoir targeted for subsurface development, improving confidence in project viability. 

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3. Parametric Study of CO2 Sequestration in Deep Saline Aquifers Using Data-Driven Models

   https://doi.org/10.2118/218906-MS  

   Khan, M I; Khanal, A (April 2024, SPE)

   Abstract Large-scale geo-sequestration of anthropogenic carbon dioxide (CO2) is one of the most promising methods to mitigate the effects of climate change without significant stress on the current energy infrastructure. However, the successful implementation of CO2 sequestration projects in suitable geological formations, such as deep saline aquifers and depleted hydrocarbon reservoirs, is contingent upon the optimal selection of decision parameters constrained by several key uncertainty parameters. This study performs an in-depth parametric analysis of different CO2 injection scenarios (water-alternating gas, continuous, intermittent) for aquifers with varying petrophysical properties. The petrophysical properties evaluated in this study include aquifer permeability, porosity, relative permeability, critical gas saturation, and others. Based on the extensive data collected from the literature, we generated a large set of simulated data for different operating conditions and geological settings, which is used to formulate a proxy model using different machine learning methods. The injection is run for 25 years with 275 years of post-injection monitoring. The results demonstrated the effectiveness of the machine learning models in predicting the CO2 trapping mechanism with a negligible prediction error while ensuring a low computational time. Each model demonstrated acceptable accuracy (R2 >0.93), with the XGBoost model showing the best accuracy with an R2 value of 0.999, 0.995, and 0.985 for predicting the dissolved, trapped, and mobile phase CO2. Finally, a feature importance analysis is conducted to understand the effect of different petrophysical properties on CO2 trapping mechanisms. The WAG process exhibited a higher CO2 dissolution than the continuous or intermittent CO2 injection process. The porosity and permeability are the most influential features for predicting the fate of the injected CO2. The results from this study show that the data-driven proxy models can be used as a computationally efficient alternative to optimize CO2 sequestration operations in deep saline aquifers effectively. 

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4. Unveiling the Essential Parameters Driving Mineral Reactions during CO2 Storage in Carbonate Aquifers through Proxy Models

   https://doi.org/10.3390/app14041465  

   Machado, Marcos Vitor; Khanal, Aaditya; Delshad, Mojdeh (February 2024, Applied Sciences)

   Numerical simulation is a commonly employed technique for studying carbon dioxide (CO2) storage processes in porous media, particularly saline aquifers. It enables the representation of diverse trapping mechanisms and the assessment of CO2 retention capacity within the subsurface. The intricate physicochemical phenomena involved necessitate the incorporation of multiphase flow, accurate depiction of fluid and rock properties, and their interactions. Among these factors, geochemical reaction rates and mechanisms are pivotal for successful CO2 trapping in carbonate reactive rocks. However, research on kinetic parameters and the influence of lithology on CO2 storage remains limited. This limitation is partly due to the challenges faced in laboratory experiments, where the time scale of the reactions and the lack of in situ conditions hinder accurate measurement of mineral reaction rates. This study employs proxy models constructed using response surfaces calibrated with simulation results to address uncertainties associated with geochemical reactions. Monte Carlo simulation is utilized to explore a broader range of parameters and identify influential factors affecting CO2 mineralization. The findings indicate that an open database containing kinetic parameters can support uncertainty assessment. Additionally, the proxy models effectively represent objective functions related to CO2 injectivity and mineralization, with calcite dissolution playing a predominant role. pH, calcite concentration, and CO2 injection rate significantly impact dolomite precipitation, while quartz content remains unaffected. 

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5. Experimental Study to Investigate CO2 Mediated Oil Flow in Nanopores

   https://doi.org/10.2118/220726-MS  

   Hegazy, D A; Yin, X; Qiao, R; Ozkan, E (September 2024, SPE)

   Abstract To optimize CO2 EOR operations, such as Huff and Puff (HnP), it is necessary to have a good understanding of oil- CO2 transport both at nanopore and at reservoir scales. In this study, experiments were performed to investigate how pore adsorbed CO2 can mediate oil flow in analog nanopore arrays. These experiments quantified how much interfacial CO2 contributed to improving permeability to oil in nanopores, in addition to increasing mobility by viscosity reduction. The experimental procedure involved flowing C10 (decane) with and without CO2 through an Anodic Aluminum Oxide (AAO) membrane at a defined differential pressure and recording flow rate. Viscosity obtained from correlations was then used to calculate membrane pore permeability. Inlet pump pressure was lower than the oil-CO2 miscibility pressure at the test conditions. Pore permeability improvement due to pore wall adsorbed CO2 was computed by isolating the effect of viscosity reduction of the bulk fluid. An overall pore-permeability increase of 15% was observed in the CO2 and C10 mixture experiments compared to the C10-only experiments, due to interfacial CO2. These results lend support to the previous molecular dynamics simulations, which predicted that interfacial CO2 can significantly modulate C10 flow in nanopores up to 10 nm diameter (Moh et al. 2020). Some differences from the molecular dynamics simulations of Moh et al. (2020) observed in the experimental study also verify the potential contribution of other phenomena to the permeability enhancement of the nanoporous membrane in the presence of CO2. Therefore, this study provides further impetus for exploring the unique nanofluidic physics of oil and CO2 transport arising from CO2 at oil-wall interfaces. The demonstrated significance of the unique nanopore phenomena, which have not been observed and incorporated into large-scale flow models, emphasizes the importance of identifying and incorporating nanofluidic physics into commercial reservoir simulators' transport models for better representation of CO2 and oil flow in unconventional reservoirs. 

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