Search Results (17)

This article addresses the storage of carbon dioxide [CO₂] in underground geological formations. It presents the results of a preliminary assessment of the feasibility of sequestering CO₂ in Cambrian aquifer units located within the Polish Exclusive Economic Zone of the Baltic Sea. The northern segment of a structure within the Rozewie tectonic block was selected as the research and test site. The aim was to determine the sequestration capacity and select optimal locations for injection wells, taking into account storage safety. The results and conclusions are based on numerical simulations of CO₂ injection and plume migration within a brine-filled structure using Petromod software v. 2024. A geological model of the site was developed representing the spatial distribution of petrophysical parameters (porosity and permeability) of the reservoir and sealing horizons. Fault zones were also mapped and parameterised in order to evaluate the structural integrity and identify potential migration barriers for the injected gas. An initial assessment assumed the possibility of injecting 100 Mt of CO₂ into the analyzed structure over a 30-year period using ten wells. However, simulation results based on the current state of geological characterization demonstrated that injection performance may vary considerably between individual wells. Wells situated within zones of highest reservoir capacity were estimated to sustain injection rates of 6–7 Mt of CO₂ over 30 years, implying that a greater number of injection wells would be required to accommodate the target storage amount. Fault seal capacity was evaluated using an algorithm based on the Shale Gouge Ratio (SGR) criterion, which enabled the assessment of fault permeability and revealed potential risks of CO₂ leakage. Numerical simulations further facilitated the estimation of the reservoir’s storage potential and the optimization of injection well placement, considering both injection efficiency and the risk associated with CO₂ migration and leakage. Full article

This study investigates the impact of injection depth on CO₂ plume migration dynamics in saline aquifers, a critical aspect of secure and efficient carbon capture, utilization, and storage (CCUS). While CCUS offers a vital pathway for mitigating greenhouse gas emissions, challenges such as buoyancy-driven flow, salinity effects, and potential leakage threaten long-term CO₂ containment. Using compositional reservoir simulation (CMG GEM 2021.10, Calgary, Canada) and Illinois Basin Decatur Project (IBDP) data, we modeled CO₂ injection into a 10,000 ppm salinity aquifer, evaluating the effects of single- and multi-depth injection (5370 to 5385 ft). The results demonstrate that multi-depth injection significantly enhances CO₂–brine contact area, promoting dissolution trapping and mitigating buoyancy-driven migration. This enhanced dissolution and residual trapping improves horizontal containment and overall storage security in the modeled salinity environment. The work provides valuable insights for optimizing injection strategies to maximize CO₂ storage efficiency and minimize leakage risks. Full article

The increasing level of anthropogenic CO₂ in the atmosphere has made it imperative to investigate an efficient method for carbon sequestration. Geological carbon sequestration presents a viable path to mitigate greenhouse gas emissions by sequestering the captured CO₂ deep underground in rock formations to store it permanently. Geochemistry, as the cornerstone of geological CO₂ sequestration (GCS), plays an indispensable role. Therefore, it is not just timely but also urgent to undertake a comprehensive review of studies conducted in this area, articulate gaps and findings, and give directions for future research areas. This paper reviews geochemistry in terms of the sequestration of CO₂ in geological formations, addressing mechanisms of trapping, challenges, and ways of mitigating challenges in trapping mechanisms; mineralization and methods of accelerating mineralization; and the interaction between rock, brine, and CO₂ for the long-term containment and storage of CO₂. Mixing CO₂ with brine before or during injection, using microbes, selecting sedimentary reservoirs with reactive minerals, co-injection of carbonate anhydrase, and enhancing the surface area of reactive minerals are some of the mechanisms used to enhance mineral trapping in GCS applications. This review also addresses the potential challenges and opportunities associated with geological CO₂ storage. Challenges include caprock integrity, understanding the lasting effects of storing CO₂ on geological formations, developing reliable models for monitoring CO₂–brine–rock interactions, CO₂ impurities, and addressing public concerns about safety and environmental impacts. Conversely, opportunities in the sequestration of CO₂ lie in the vast potential for storing CO₂ in geological formations like depleted oil and gas reservoirs, saline aquifers, coal seams, and enhanced oil recovery (EOR) sites. Opportunities include improved geochemical trapping of CO₂, optimized storage capacity, improved sealing integrity, managed wellbore leakage risk, and use of sealant materials to reduce leakage risk. Furthermore, the potential impact of advancements in geochemical research, understanding geochemical reactions, addressing the challenges, and leveraging the opportunities in GCS are crucial for achieving sustainable carbon mitigation and combating global warming effectively. Full article

The urgent need to find mitigating pathways for limiting world CO₂ emissions to net zero by 2050 has led to intense research on CO₂ sequestration in deep saline reservoirs. This paper reviews key advancements in lab- and simulation-scale research on petrophysical, geochemical, and mineralogical changes during CO₂–brine–rock interactions performed in the last 25 years. It delves into CO₂ MPD (mineralization, precipitation, and dissolution) and explores alterations in petrophysical properties during core flooding and in static batch reactors. These properties include changes in wettability, CO₂ and brine interfacial tension, diffusion, dispersion, CO₂ storage capacity, and CO₂ leakage in caprock and sedimentary rocks under reservoir conditions. The injection of supercritical CO₂ into deep saline aquifers can lead to unforeseen geochemical and mineralogical changes, possibly jeopardizing the CCS (carbon capture and storage) process. There is a general lack of understanding of the reservoir’s interaction with the CO₂ phase at the pore/grain scale. This research addresses the gap in predicting the long-term changes of the CO₂–brine–rock interaction using various geochemical reactive transport simulators. Péclet and Damköhler numbers can contribute to a better understanding of geochemical interactions and reactive transport processes. Additionally, the dielectric constant requires further investigation, particularly for pre- and post-CO₂–brine–rock interactions. For comprehensive modeling of CO₂ storage over various timescales, the geochemical modeling software called the Geochemist’s Workbench was found to outperform others. Wettability alteration is another crucial aspect affecting CO₂–brine–rock interactions under varying temperature, pressure, and salinity conditions, which is essential for ensuring long-term CO₂ storage security and monitoring. Moreover, dual-energy CT scanning can provide deeper insights into geochemical interactions and their complexities. Full article

Conventional Carbon Capture and Storage (CCS) operations use the direct injection of CO₂ in a gaseous phase from the surface as a carbon carrier. Due to CO₂ properties under reservoir conditions with lower density and viscosity than in situ brine, CO₂ flux is mainly gravity-dominated. CO₂ moves toward the top and accumulates below the top seal, thus reinforcing the risk of possible leakage to the surface through unexpected hydraulic paths (e.g., reactivated faults, fractures, and abandoned wells) or in sites without an effective sealing caprock. Considering the risks, the potential benefits of the interplay between CO₂ and an aqueous solution of formate ions (HCOO¯) were evaluated when combined to control CO₂ gravity segregation in porous media. Three combined strategies were evaluated and compared with those where either pure CO₂ or a formate solution was injected. The first strategy consisted of a pre-flush of formate solution followed by continuous CO₂ injection, and it was not effective in controlling the vertical propagation of the CO₂ plume. However, the injection of a formate solution slug in a continuous or alternated way, simultaneously with the CO₂ continuous injection, was effective in slowing down the vertical migration of the CO₂ plume and keeping it permanently stationary deeper than the surface depth. Full article

Saline aquifers have been used for CO₂ storage as a dedicated greenhouse gas mitigation strategy since 1996. Depleted gas fields are now being planned for large-scale CCS projects. Although basalt host reservoirs are also going to be used, saline aquifers and depleted gas fields will make up most of the global geological repositories for CO₂. At present, depleted gas fields and saline aquifers seem to be treated as if they are a single entity, but they have distinct differences that are examined here. Depleted gas fields have far more pre-existing information about the reservoir, top-seal caprock, internal architecture of the site, and about fluid flow properties than saline aquifers due to the long history of hydrocarbon project development and fluid production. The fluid pressure evolution paths for saline aquifers and depleted gas fields are distinctly different because, unlike saline aquifers, depleted gas fields are likely to be below hydrostatic pressure before CO₂ injection commences. Depressurised depleted gas fields may require an initial injection of gas-phase CO₂ instead of dense-phase CO₂ typical of saline aquifers, but the greater pressure difference may allow higher initial injection rates in depleted gas fields than saline aquifers. Depressurised depleted gas fields may lead to CO₂-injection-related stress paths that are distinct from saline aquifers depending on the geomechanical properties of the reservoir. CO₂ trapping in saline aquifers will be dominated by buoyancy processes with residual CO₂ and dissolved CO₂ developing over time whereas depleted gas fields will be dominated by a sinking body of CO₂ that forms a cushion below the remaining methane. Saline aquifers tend to have a relatively limited ability to fill pores with CO₂ (i.e., low storage efficiency factors between 2 and 20%) as the injected CO₂ is controlled by buoyancy and viscosity differences with the saline brine. In contrast, depleted gas fields may have storage efficiency factors up to 80% as the reservoir will contain sub-hydrostatic pressure methane that is easy to displace. Saline aquifers have a greater risk of halite-scale and minor dissolution of reservoir minerals than depleted gas fields as the former contain vastly more of the aqueous medium needed for such processes compared to the latter. Depleted gas fields have some different leakage risks than saline aquifers mostly related to the different fluid pressure histories, depressurisation-related alteration of geomechanical properties, and the greater number of wells typical of depleted gas fields than saline aquifers. Depleted gas fields and saline aquifers also have some different monitoring opportunities. The high-density, electrically conductive brine replaced by CO₂ in saline aquifers permits seismic and resistivity imaging, but these forms of imaging are less feasible in depleted gas fields. Monitoring boreholes are less likely to be used in saline aquifers than depleted gas fields as the latter typically have numerous pre-existing exploration and production well penetrations. The significance of this analysis is that saline aquifers and depleted gas fields must be treated differently although the ultimate objective is the same: to permanently store CO₂ to mitigate greenhouse gas emissions and minimise global heating. Full article

This paper summarizes the results of the risk analysis and characterization of the CO₂ and brine leakage potential of Farnsworth Unit (FWU) site wells. The study is part of the U.S. DOE’s National Risk Assessment Partnership (NRAP) program, which aims to quantitatively evaluate long-term environmental risks under conditions of significant geologic uncertainty and variability. To achieve this, NRAP utilizes risk assessment and computational tools specifically designed to quantify uncertainties and calculate the risk associated with geologic carbon dioxide (CO₂) sequestration. For this study, we have developed a workflow that utilizes physics-based reservoir simulation results as input to perform leakage calculations using NRAP Tools, specifically NRAP-IAM-CS and RROM-Gen. These tools enable us to conduct leakage risk analysis based on ECLIPSE reservoir simulation results and to characterize wellbore leakage at the Farnsworth Unit Site. We analyze the risk of leakage from both individual wells and the entire field under various wellbore integrity distribution scenarios. The results of the risk analysis for the leakage potential of FWU wells indicate that, when compared to the total amount of CO₂ injected, the highest cemented well integrity distribution scenario (FutureGen high flow rate) exhibits approximately 0.01% cumulative CO₂ leakage for a 25-year CO₂ injection duration at the end of a 50-year post-injection monitoring period. In contrast, the highest possible leakage scenario (open well) shows approximately 0.1% cumulative CO₂ leakage over the same time frame. Full article

Potential CO₂ leakage from deep geologic reservoirs requires evaluation on a site-specific basis to assess risk and arrange mitigation strategies. In this study, a heterogeneous and realistic numerical model was developed to investigate CO₂ migration pathways and uprising time in a shaly overburden, located in the Malaysian off-shore. Fluid flow and reactive transport simulations were performed by TOUGHREACT to evaluate the: (1) seepage through the caprock; (2) CO₂-rich brine leakage through a fault connecting the reservoir with seabed. The effect of several factors, which may contribute to CO₂ migration, including different rock types and permeability, Fickian and Knudsen diffusion and CO₂ adsorption in the shales were investigated. Obtained results show that permeability mainly ruled CO₂ uprising velocity and pathways. CO₂ migrates upward by buoyancy without any important lateral leakages due to poor-connection of permeable layers and comparable values of vertical and horizontal permeability. Diffusive flux and the Knudsen flow are negligible with respect to the Darcy regime, despite the presence of shales. Main geochemical reactions deal with carbonate and pyrite weathering which easily reach saturation due to low permeability and allowing for re-precipitation as secondary phases. CO₂ adsorption on shales together with dissolved CO₂ constituted the main trapping mechanisms, although the former represents likely an overestimation due to estimated thermodynamic parameters. Developed models for both scenarios are validated by the good agreement with the pressure profiles recorded in the exploration wells and the seismic data along a fault (the F05 fault), suggesting that they can accurately reproduce the main processes occurring in the system. Full article

Wettability in CO₂-brine-mineral/rock systems is an important parameter influencing CO₂ storage capacities and leakage risks in saline reservoirs. However, CO₂ tends to react with various minerals and rocks at subsurface conditions, thus causing temporal and spatial wettability changes. Although many relevant research works have been published during past years, a thorough overview of this area is still lacking. Therefore herein, reaction-induced wettability changes are reviewed, and the underlying mechanisms are discussed. Current research gaps are identified, future outlooks are suggested, and some conclusions are drawn. The fundamental understanding of reaction-induced mineral and rock wettability changes during CO₂ storage in saline reservoirs is analyzed and the guidance for long-term CO₂ containment security evaluations is provided. Full article

Geological sequestration of acid gases, including CO₂, is now a growing solution to prevent progressive Earth climate change. Disposal of environmentally harmful greenhouse gases must be performed safely and securely to minimise leakage risk and possible uncontrolled emissions of injected gases outside the sequestration structure. The paper describes a series of research activities at the Borzęcin sequestration site located in western Poland, which were designed to study the migration paths of injected acid gases (mainly mixture of CO₂ and H₂S) into the water-bearing layers underlying natural gas reservoir. Along with understanding the nature and dynamics of acid gases migration within the sequestration structure, the research was also addressed to assess its leak-tightness and the long-term safety of the entire reinjection facility. As a part of the research works, two downhole sampling campaigns were completed in 2018–2019, where samples of water underlying the Borzęcin reservoir were taken and subsequently studied to determine their physicochemical parameters that were never before examined. Compositions of gas dissolved in downhole brine samples were compared with produced and injected gas. Relevant studies of reservoir water from selected wells were performed, including isotopic analyses. Finally, four series of soil gas analyses were performed on the area surrounding the selected well, which are important for the hazardous gas sequestration safety analysis in the Borzęcin facility. All the above mentioned research activities aimed to acquire additional knowledge, which is valuable for risk assessment of the acid gas sequestration process taking place on the specific example of the Borzęcin site operating continuously since 1996. Full article

Geological storage of CO₂ in saline aquifers and depleted oil and gas reservoirs can help mitigate CO₂ emissions. However, CO₂ leakage over a long storage period represents a potential concern. Therefore, it is critical to establish a good understanding of the interactions between CO₂–brine and cement–caprock/reservoir rock to ascertain the potential for CO₂ leakage. Accordingly, in this work, we prepared a unique set of composite samples to resemble the cement–reservoir rock interface. A series of experiments simulating deep wellbore environments were performed to investigate changes in chemical, physical, mechanical, and petrophysical properties of the composite samples. Here, we present the characterisation of composite core samples, including porosity, permeability, and mechanical properties, determined before and after long-term exposure to CO₂-rich brine. Some of the composite samples were further analysed by X-ray microcomputed tomography (X-ray µ-CT), X-ray diffraction (XRD), and scanning electron microscopy–energy-dispersive X-ray (SEM–EDX). Moreover, the variation of ions concentration in brine at different timescales was studied by performing inductively coupled plasma (ICP) analysis. Although no significant changes were observed in the porosity, permeability of the treated composite samples increased by an order of magnitude, due mainly to an increase in the permeability of the sandstone component of the composite samples, rather than the cement or the cement/sandstone interface. Mechanical properties, including Young’s modulus and Poisson’s ratio, were also reduced. Full article

Carbon capture and storage (CCS) has been increasingly looking like a promising strategy to reduce ${\mathrm{CO}}_2$ emissions and meet the Paris agreement’s climate target. To ensure that CCS is safe and successful, an efficient monitoring program that will prevent storage reservoir leakage and drinking water contamination in groundwater aquifers must be implemented. However, geologic ${\mathrm{CO}}_2$ sequestration (GCS) sites are not completely certain about the geological properties, which makes it difficult to predict the behavior of the injected gases, ${\mathrm{CO}}_2$ brine leakage rates through wellbores, and ${\mathrm{CO}}_2$ plume migration. Significant effort is required to observe how ${\mathrm{CO}}_2$ behaves in reservoirs. A key question is: Will the ${\mathrm{CO}}_2$ injection and storage behave as expected, and can we anticipate leakages? History matching of reservoir models can mitigate uncertainty towards a predictive strategy. It could prove challenging to develop a set of history matching models that preserve geological realism. A new Bayesian evidential learning (BEL) protocol for uncertainty quantification was released through literature, as an alternative to the model-space inversion in the history-matching approach. Consequently, an ensemble of previous geological models was developed using a prior distribution’s Monte Carlo simulation, followed by direct forecasting (DF) for joint uncertainty quantification. The goal of this work is to use prior models to identify a statistical relationship between data prediction, ensemble models, and data variables, without any explicit model inversion. The paper also introduces a new DF implementation using an ensemble smoother and shows that the new implementation can make the computation more robust than the standard method. The Utsira saline aquifer west of Norway is used to exemplify BEL’s ability to predict the ${\mathrm{CO}}_2$ mass and leakages and improve decision support regarding ${\mathrm{CO}}_2$ storage projects. Full article

Potential leakage of reservoir fluids is considered a key risk factor for geologic CO₂ sequestration (GCS), with concerns of their chemical impacts on the quality of overlying underground sources of drinking water (USDWs). Effective risk assessment provides useful information to guide GCS activities for protecting USDWs. In this study, we present a quantified risk assessment case study of an active commercial-scale CO₂-enhanced oil recovery (CO₂-EOR) and sequestration field, the Farnsworth Unit (FWU). Specific objectives of this study include: (1) to quantify potential risks of CO₂ and brine leakage to the overlying USDW quality with response surface methodology (RSM); and (2) to identify water chemistry indicators for early detection criteria. Results suggest that trace metals (e.g., arsenic and selenium) are less likely to become a risk due to their adsorption onto clay minerals; no-impact thresholds based on site monitoring data could be a preferable reference for early groundwater quality evaluation; and pH is suggested as an indicator for early detection of a leakage. This study may provide quantitative insight for monitoring strategies on GCS sites to enhance the safety of long-term CO₂ sequestration. Full article

Driven by concerns for safe storage of CO₂, substantial effort has been directed on wellbore integrity simulations over the last decade. Since large scale demonstrations of CO₂ storage are planned for the near-future, numerical tools predicting wellbore integrity at field scale are essential to capture the processes of potential leakage and assist in designing leakage mitigation measures. Following this need, we developed a field-scale wellbore model incorporating (1) a de-bonded interface between cement and rock, (2) buoyancy/pressure driven (microannulus) flow of brine and CO₂, (3) CO₂ diffusion and reactivity with cement and (4) chemical cement-rock interaction. The model is aimed at predicting leakage through the microannulus and specifically at assessing methods for CO₂ leakage remediation. The simulations show that for a low enough initial leakage rate, CO₂ leakage is self-limiting due to natural sealing of the microannulus by mineral precipitation. With a high leakage rate, CO₂ leakage results in progressive cement leaching. In case of sustained leakage, a CO₂ reactive solution can be injected in the microannulus to induce calcite precipitation and block the leak path. The simulations showed full clogging of the leak path and increased sealing with time after remediation, indicating the robustness of the leakage remediation by mineral precipitation. Full article

The risk of CO₂ leakage from damaged wellbore is identified as a critical issue for the feasibility and environmental acceptance of CO₂ underground storage. For instance, Portland cement can be altered if flow of CO₂-rich water occurs in hydraulic discontinuities such as cement-tubing or cement-caprock interfaces. In this case, the raw cement matrix is altered by diffusion of the solutes. This fact leads to the formation of distinctive alteration fronts indicating the dissolution of portlandite, the formation of a carbonate-rich layer and the decalcification of the calcium silicate hydrate, controlled by the interplay between the reaction kinetics, the diffusion-controlled renewing of the reactants and products, and the changes in the diffusion properties caused by the changes in porosity induced by the dissolution and precipitation mechanisms. In principle, these mass transfers can be easily simulated using diffusion-reaction numerical models. However, the large uncertainties of the parameters characterizing the reaction rates (mainly the kinetic and thermodynamic coefficients and the evolving reactive surface area) and of the porosity-dependent diffusion properties prevent making reliable predictions required for risk assessment. In this paper, we present the results of a set of experiments consisting in the alteration of a holed disk of class-G cement in contact with a CO₂-rich brine at reservoir conditions (P = 12 MPa and T = 60 °C) for various durations. This new experimental protocol allows producing time-resolved data for both the spatially distributed mass transfers inside the cement body and the total mass transfers inferred from the boundary conditions mass balance. The experimental results are used to study the effect of the fluid salinity and the pCO₂ on the overall reaction efficiency. Experiments at high salinity triggers more portlandite dissolution, thinner carbonate layers, and larger alteration areas than those at low salinity. These features are accompanied with different spatial distribution of the alteration layers resulting from a complex interplay between salinity-controlled dissolution and precipitation mechanisms. Conversely, the effect of the pCO₂ is more intuitive: Increasing pCO₂ results in increasing the overall alteration rate without modifying the relative distribution of the reaction fronts. Full article