Geologic Carbon Sequestration Research Articles

Carbon Dioxide (CO2) Dissolution Efficiency During Geological Carbon Sequestration (GCS) in Randomly Stratified Formations

AbstractGeological carbon sequestration mitigates climate change by capturing and storing carbon dioxide (CO2) emissions in deep geologic formations. Dissolution trapping is one mechanism by which CO2 can be trapped in a deep formation. However, heterogeneity can significantly affect the dissolution efficiency. This work addresses the injection of CO2 in perfectly stratified saline formations under uncertainty. Monte Carlo two‐phase flow compositional simulations involving the dissolution of CO2 into brine and evaporation of water into the CO2‐rich phase are presented. We systematically analyzed the interplay between heterogeneity and gravity factor (G), which is shown to control the migration of the CO2 plume as well as the temporal evolution of dissolution efficiency. Results show that when G is important, vertical segregation controls the overall behavior of CO2, diminishing the influence of small‐scale heterogeneity on dissolution. However, when G is relatively small compared to , CO2 migrates preferentially through high permeability layers and dissolution efficiency increases with due to the stretching of the CO2 plume that enhances mixing. As a result, in this situation, the upscaling of permeability leads to an underestimation of the dissolution efficiency. A review of field sites shows that dissolution is heterogeneity‐controlled in most real systems. Knowing that most numerical models cannot afford to represent heterogeneity at an adequate scale, results indicate that dissolution efficiency can be typically underestimated by a factor close to 1.5.

Potential Seismicity Along Basement Faults Induced by Geological Carbon Sequestration

AbstractLarge‐scale CO2 sequestration into geological formations has been suggested to reduce CO2 emissions from industrial activities. However, much like enhanced geothermal stimulation and wastewater injection, CO2 sequestration has a potential to induce earthquake along weak faults, which can be considered a negative impact on safety and public opinion. This study shows the physical mechanisms of potential seismic hazards along basement faults driven by CO2 sequestration under variation in geological and operational constraints. Specifically we compare the poroelastic behaviors between multiphase flow and single‐phase flow cases, highlighting specific needs of evaluating induced seismicity associated with CO2 sequestration. In contrast to single‐phase injection scenario, slower migration of the CO2 plume than pressure pulse may delay accumulation of pressure and stress along basement faults that may not be mitigated immediately by shut‐in of injection. The impact of multiphase flow system, therefore, needs to be considered for proper monitoring and mitigation strategies.

The major techniques, advantages, and pitfalls of various methods used in geological carbon sequestration

The major techniques, advantages, and pitfalls of various methods used in geological carbon sequestration

Influence of Caprock Morphology on Solubility Trapping during CO2 Geological Sequestration

Carbon capture and sequestration (CCS) technology is one of the indispensable alternatives to reduce carbon dioxide (CO2) emissions. In this technology, carbon capture and transport grid will send CO2 to the storage facilities that are using various storage techniques. Geologic carbon sequestration (GCS) is one such storage technique where CO2 is injected into a deep geological subsurface formation. The injected CO2 is permanently stored in the formation due to structural, residual, solubility, and mineral trapping phenomena. Among different trapping mechanisms, solubility trapping plays a significant role in the safe operation of GCS. In this work, the study is conducted to elucidate the influence of top surface caprock morphology on the solubility trapping mechanism. The simulation results show that the naturally available heterogeneous formations with anticline and without anticline structure influence the solubility fingering phenomena and solubility entrapment percentage over a geological time scale. The lateral migration and sweeping efficiency results of both the synthetic domains for the injected CO2 have shown the importance of caprock morphology on solubility trapping and selection of injection rate. Quantification of solubility trapping in two morphological structures revealed that the synthetic domain without anticline morphology had shown higher solubility trapping. In the future, the simulation data using Artificial Neural Networks can be applied to predict the structural and solubility trapping of geological formations. This analysis further helps incorporating the interaction of CO2 with porous media leading to a mineral trapping mechanism.

Coupled hydromechanical model for evaluating the volume change and fluid permeation behavior of expansive clay smear in a fault upon interaction with CO2

The interaction between clay minerals and CO2 at in-situ conditions of geological carbon sequestration leads to adsorption-induced strain, which increases the mineral's interlayer space. The effect of change in interlayer spacing of minerals on the evolution of macro-permeability, gas storage capacity, gas pore pressure, and stress state of compacted clays is unknown. The present study described a coupled numerical model to investigate the effect of adsorption-induced swelling of smectite-based clay on its gas permeation and mechanical properties upon interaction with CO2. To simulate the interaction of the fill material present in caprock faults with the injected CO2, compacted clay under confined, free and uniaxial confinement conditions are analyzed. It is evident under confined conditions, permeability of the clay filled in fault reduced, and mean compressive stress increased due to gas adsorption-induced strain. On the contrary, the permeability of the clay increased for both free and uniaxial conditions. The magnitude of the swelling stress within the media under uniaxial conditions depends on the degree of expansion caused by the adsorption-induced effect and applied overburden pressure. Overall, the study contributes to a comprehensive approach to evaluate the efficacy of geological formations having faults for long-term storage of CO2 in them.

Velocity modeling of supercritical pore fluids through porous media under reservoir conditions with applications for petroleum secondary migration and carbon sequestration plumes

Computational methods to characterize secondary migration in porous media traditionally rely on fluid transport equations with assumptions of time invariance, such as flow-path modeling of buoyancy vectors, statistical percolation algorithms, capillary pressure curves, or a form of Darcy’s law, which presumes instantaneous fluid transport. However, in petroleum systems modeling, the timeframe of secondary migration from source to reservoir is important to quantify in relation to other geologic factors, such as the timing of petroleum generation, fault movement, and seal formation. In addition, quantifying migration velocities enables an estimation of the distance a plume of geologically sequestered carbon dioxide travels over time, as well as the identification of low-permeability strata appropriate for long-term containment. This study introduces a method to quantify transport velocities of supercritical fluids in low-permeability lithologies for a broad range of rock and fluid properties likely encountered in the sedimentary sequence. A time-dependent form of Darcy’s law for pressure-driven viscous flow through homogeneous isotropic porous media was used to model flow velocities within a carrier bed. Thermodynamic equations of state were used to determine thermophysical properties of supercritical pore fluids under reservoir pressures ranging from 0 MPa to 200 MPa (0–29,000 psi) to constrain the momentum equations. Three case studies were examined that (1) estimated fluid flow velocities of methane within the low-permeability Upper Jurassic Haynesville Formation, (2) defined permeability-based flow units to evaluate saline formations for long-term geologic carbon sequestration, and (3) calculated the migration distance of carbon dioxide plumes at the Decatur, Illinois injection and sequestration project.

Leakage From Coexisting Geologic Forcing and Injection‐Induced Pressurization: A Semi‐Analytical Solution for Multilayered Aquifers With Multiple Wells

AbstractAbnormal fluid pressures (above or below hydrostatic pressure) can develop and persist in sedimentary basins. The common occurrence of abnormal pressures may cause challenges for project permitting of geological carbon sequestration (GCS), particularly in reservoirs with pre‐injection overpressure. The leaky wells that may exist in some sedimentary basins can provide flow paths between deep brine aquifers and shallower freshwater aquifers. Pre‐injection relative overpressures can cause brine leakage through leaky wells even before any injection occurs. The tendency for flow through leaky wells is coupled with the process of pressure dissipation that occurs through aquitards. Specifically, with non‐zero permeability, aquitards can dissipate pressure over large areal extents and thereby reduce leakage rates through leaky wells. This study presents development of a semi‐analytical solution for hydraulic head and brine leakage in multilayered aquifer–aquitard systems with geologic pressure forcing. The geologic forcing that causes abnormal pressures in the multilayered system can coexist with any number of injection, extraction, and leaky wells that also affect fluid pressure. The semi‐analytical model is applied to explore how leakage through leaky wells varies as functions of pressurization rate, along with aquitard and leaky well properties in an overpressured multilayered system. The results show that although injection‐induced pressures can dissipate rapidly through suitably permeable aquitards, coexisting geologic forcing may create sustained rates of brine leakage into freshwater aquifers through leaky wells. In GCS, a very low‐permeability aquitard with high capillary entry pressure to free‐phase CO2 is desired to serve as the caprock to prevent leakage of CO2 from the storage reservoir. Nevertheless, the results from this study show that the brine leakage impact to shallow freshwater aquifers through leaky wells might substantially decrease with increasing aquitard permeability values, as long as small aquitard permeability and high capillary entry pressure serve to prevent CO2 leakage.

Coupled Hydromechanical Modeling of Induced Seismicity From CO2 Injection in the Illinois Basin

AbstractInjection of CO2 for geologic carbon sequestration into deep sedimentary formations involves fluid pressure increases that engage hydromechanical processes that can cause seismicity by activation of existing faults. In this work, we use a coupled multiphase fluid flow and geomechanical simulator to model spatiotemporal fluid pressure and stress changes in order to study the poroelastic effect of CO2 injection on faults in crystalline basement rock below the injection zone. The seismicity rate along features interpreted to be basement faults is modeled using Dieterich's rate‐and‐state earthquake nucleation model. The methodology is applied to microseismicity detected during CO2 injection into the Mount Simon formation during the Illinois Basin—Decatur Project. The modeling accurately captures an observed reduction in seismicity rate when the injection in the second well was into a slightly shallower zone above the base of the Mount Simon formation. Moreover, the modeling shows that it is important to consider poroelastic stress changes, in addition to fluid pressure changes for accurately modeling of the observed seismicity rate.

Editorial: Reservoir Processes and Global Practices in Geologic Carbon Sequestration

Editorial: Reservoir Processes and Global Practices in Geologic Carbon Sequestration

Downwind dispersion of CO2 from a major subsea blowout in shallow offshore waters

AbstractGrowing interest in offshore geologic carbon sequestration (GCS) motivates risk assessment of large‐scale subsea CO2 well blowouts or pipeline ruptures. For major leaks of CO2 from wells or pipelines, significant fluxes of CO2 may occur from the sea surface depending on water depth. In the context of risk assessment of human health and safety, we have used previously simulated coupled well‐reservoir and water column model results as a source term for dense gas dispersion of CO2 above the sea surface. The models are linked together by one‐way coupling, that is, output of one model is used as input to the next model. These first‐of‐their‐kind coupled flow results are applicable to assessing the hazard of CO2 to people at and downwind of the sea surface location of emission. Hazard is quantified by plotting the downwind dispersion length (DDL), which we define in the study as the distances from the emission source to the point at which the emitted CO2 has been diluted to 5% and 1.5% in air by volume. Results suggest that large‐scale blowouts in shallow water (10 m) may cause hazardous CO2 plumes extending on the order of several hundred meters downwind. Details of the modeling show DDL has a maximum for windspeed (at an elevation of 10 m) of approximately 5 m/s, with smaller DDL for both weaker and stronger winds. This is explained by the fact that wind favors transport but also causes dispersion; therefore there is a certain wind speed that maximizes DDL. © 2022 Society of Chemical Industry and John Wiley & Sons, Ltd.

Hydro-thermo-chemo-mechanical modeling of carbon dioxide injection in fluvial heterogeneous aquifers

Understanding geological sequestration of carbon dioxide (CO2) requires fully-coupled simulation of thermal-hydrological-mechanical-chemical (THMC) processes within well-characterized subsurface heterogeneity. A CO2 injection pilot project was performed in the Cranfield site, Mississippi, USA, where subsurface heterogeneity reflects fluvial deposition. During the project, CO2 was injected through an injection well and was monitored using two observation wells. We incorporate high-resolution three-dimensional heterogeneity model of the site into multiphase and multi-component flow and transport models. We validate our models and evaluate how bottom-hole pressure (BHP) in injection well, CO2 breakthrough times at observation wells, and efficiency of trapping mechanisms (i.e., dissolution, snap-off trapping, mobile CO2) are controlled by (1) non-isothermal CO2 injection, (2) geochemical reactions, (3) capillary pressure heterogeneity, (4) geomechanical effects, and (5) permeability enhancement close to the injection well. Results suggest that neglecting thermal effects lowers BHP, shortens breakthrough times, overestimates dissolution, and underestimates snap-off trapping. The BHP remains unchanged, breakthrough times are overestimated, and solubility and snap-off trapping are underestimated when geochemical reactions are ignored. Ignoring capillary pressure heterogeneity results in underestimation of BHP and dissolution and overestimation of breakthrough times. Ignoring geomechanical process results in lower BHP, shorter breakthrough times, increased dissolution, and decreased snap-off trapping. Ignoring permeability enhancement results in underestimation of breakthrough times and solubility trapping, and overestimation of snap-off trapping. Our results have important practical implication for designing effective field scale experiments and numerical simulations of geological carbon sequestration. Other multiphase flow problems in which subsurface heterogeneities are the main controlling factor (e.g., hydrogen storage) may benefit from this work.

Creep of CarbFix basalt: influence of rock–fluid interaction

Abstract. Geological carbon sequestration provides permanent CO2 storage to mitigate the current high concentration of CO2 in the atmosphere. CO2 mineralization in basalts has been proven to be one of the most secure storage options. For successful implementation and future improvements of this technology, the time-dependent deformation behavior of reservoir rocks in the presence of reactive fluids needs to be studied in detail. We conducted load-stepping creep experiments on basalts from the CarbFix site (Iceland) under several pore fluid conditions (dry, H2O saturated and H2O + CO2 saturated) at temperature, T≈80 ∘C and effective pressure, Peff=50 MPa, during which we collected mechanical, acoustic and pore fluid chemistry data. We observed transient creep at stresses as low as 11 % of the failure strength. Acoustic emissions (AEs) correlated strongly with strain accumulation, indicating that the creep deformation was a brittle process in agreement with microstructural observations. The rate and magnitude of AEs were higher in fluid-saturated experiments than in dry conditions. We infer that the predominant mechanism governing creep deformation is time- and stress-dependent subcritical dilatant cracking. Our results suggest that the presence of aqueous fluids exerts first-order control on creep deformation of basaltic rocks, while the composition of the fluids plays only a secondary role under the studied conditions.

Time-lapse seismic data inversion for estimating reservoir parameters using deep learning

Geologic carbon sequestration involves the injection of captured carbon dioxide ([Formula: see text]) into subsurface formations for long-term storage. The movement and fate of the injected [Formula: see text] plume is of great concern to regulators because monitoring helps to identify potential leakage zones and determines the possibility of safe long-term storage. To address this concern, we design a deep-learning framework for [Formula: see text] saturation monitoring to determine the geologic controls on the storage of the injected [Formula: see text]. We use different combinations of porosities and permeabilities for a given reservoir to generate saturation and velocity models. We train the deep-learning model with a few time-lapse seismic images and their corresponding changes in saturation values for a particular [Formula: see text] injection site. The deep-learning model learns the mapping from the change in the time-lapse seismic response to the change in [Formula: see text] saturation during the training phase. We then apply the trained model to data sets comprising different time-lapse seismic image slices (corresponding to different time instances) generated using different porosity and permeability distributions that are not part of the training to estimate the [Formula: see text] saturation values along with the plume extent. Our algorithm provides a deep-learning assisted framework for the direct estimation of [Formula: see text] saturation values and plume migration in heterogeneous formations using the time-lapse seismic data. Our method improves the efficiency of time-lapse inversion by streamlining the large number of intermediate steps in the conventional time-lapse inversion workflow. This method also helps to incorporate the geologic uncertainty for a given reservoir by accounting for the statistical distribution of porosity and permeability during the training phase. Tests on different examples verify the effectiveness of our approach.

Evaluating Top Seals within a Sequence Stratigraphic Framework: Impact on Geological Carbon Sequestration

Evaluating Top Seals within a Sequence Stratigraphic Framework: Impact on Geological Carbon Sequestration

Influence of relative permeability, capillary pressure, and well orientation in the geological carbon sequestration in a saline aquifer

Influence of relative permeability, capillary pressure, and well orientation in the geological carbon sequestration in a saline aquifer

Techno-socio-economic analysis of geological carbon sequestration opportunities

Although geological carbon sequestration is considered one of the pillars required to achieve the goals of the Paris Agreement, only a few demonstration sites are currently being developed around the globe. A workflow is presented here to identify potential new pilot sites.

Influence of relative permeability, capillary pressure, and well orientation in the geological carbon sequestration in a saline aquifer

Influence of relative permeability, capillary pressure, and well orientation in the geological carbon sequestration in a saline aquifer

Permeability evolution of defective wellbore cement under geologic carbon sequestration conditions by means of varying-radius pipeline modeling

X-ray imaging in combination with image registration was employed to unveil the microstructure alteration of defective wellbore cement cores when exposed to stagnant or flowing CO2-saturated brine under geologic carbon sequestration conditions. A varying-radius pipeline (VRP) modeling approach is proposed for estimating the permeability alteration from computed tomography (CT) images of artificial channels in the cement cores. The VRP model simplifies the three-dimensional channels into varying-radius pipelines, solves the problem of flow with one-dimensional Navier‒Stokes equations, and can readily be coupled with the Cahn–Hilliard equation to address multiphase flow problems. Furthermore, the accuracy of VRP modeling was verified by permeability testing and direct pore-scale modeling. The channel after CO2 exposure in the reactive-diffusion process was covered by substantial precipitation of calcite, and the measured channel permeability decreased by 28.67% from the original value 4.15 × 10−8 m2. In contrast, the channel after CO2 exposure in the reactive-flow process underwent significant dissolution, substantial tensile microfractures occurred at channel surface, and the measured channel permeability increased by 8.18% from the original 3.91 × 10−8 m2. The CT image–based microstructure investigation implied that when exposed to immobile CO2-saturated brine, even large fluid channels in wellbore cement may be shielded from further degradation; however, when encountering flowing CO2-saturated brine, cement with large fluid channels may fail. The proposed VRP model has the potential to assess field-scale CO2 leakage in wells.

Model‐Reduced Adjoint‐Based Inversion Using Deep‐Learning: Example of Geological Carbon Sequestration Modeling

AbstractAs an extension of our previous research on deep‐learning‐based adjoint‐state approach (Xiao, Deng, & Wang, 2021, https://doi.org/10.1029/2020wr027400), we present a two‐level hybrid neural network architecture to efficiently derive a model‐reduced adjoint‐based optimization workflow with a large‐scale inverse modeling example in geological carbon‐storage applications. The first level employs a nonlinear dimensionality reduction technique, that is, deep convolutional autoencoder, owing to its high scalability and the availability of high‐performance deep‐learning libraries for flexible implementation. Analogous to the reduced‐order linear model, the second level emulates a neural‐network‐powered linear transition unit based on the reduced subspace. This hybrid framework provides a readily available model‐reduced adjoint derivation with negligible computational cost and computer storage. Once the gradient is obtained in reduced space, it is correspondingly projected back to full space for the inverse modeling. The performance of the method is verified by estimating the space‐dependent stochastic permeability field using two geological carbon storage (GCS) process‐based multiphase flow models with an increasing complexity. The experimental results indicate that the surrogate model can accurately characterize the spatial‐temporal evolution of the CO2 saturation fields using a relatively small number of training data. Although the proposed inversion workflow achieves comparable results similar to the conventional finite‐difference method, it is faster than high‐fidelity model simulations in several orders of magnitude; hence, it will be a beneficial simulation and modeling tool for engineers to manage the uncertainty of GCS processing.

Diagnostic and predictive analysis of production and injection‐induced fault activation

AbstractMitigating the hazard of fault reactivation during CO injection and oil production is important for ensuring environmental sustainability of geologic carbon sequestration and hydrocarbon recovery. Currently, we do not know how the Coulomb Failure Stress (CFS), which is a commonly used metric to assess the potential of inducing slip on a fault, evolves differently for gas injection and oil production scenarios. Using high‐resolution simulations of CO injection‐induced and oil production‐induced fault slip and theories of Coulomb failure and poroelasticity, we address this gap in knowledge. We analyze the fault tractions, slip, and reservoir pressure to understand how a fault is destabilized in successive steps, how hypocenter locations are selected, and how these processes differ between injection and production. We extract and summarize the characteristic features of induced fault activation in terms of the dependence of CFS and the Fault Stress Ratio (FSR) on the dimensionless reservoir pressure perturbation caused by injection or production. We apply the framework to the Farnsworth oilfield in Texas, which is undergoing CO injection and oil production, to disambiguate observations related to fault stability. Finally, we discuss how our framework can inform models that aim to forecast fluid flow‐induced slip and mitigate the induced seismicity hazard in oilfields and gas storage sites.