Effect of sedimentary heterogeneities in the sealing formation on predictive analysis of geological CO₂ storage

Numerical models of geologic carbon sequestration (GCS) in saline aquifers use multiphase fluid flow-characteristic curves (relative permeability and capillary pressure) to represent the interactions of the non-wetting CO2 and the wetting brine. Relative permeability data for many sedimentary formations is very scarce, resulting in the utilisation of mathematical correlations to generate the fluid flow characteristics in these formations. The flow models are essential for the prediction of CO2 storage capacity and trapping mechanisms in the geological media. The observation of pressure dissipation across the storage and sealing formations is relevant for storage capacity and geomechanical analysis during CO2 injection. This paper evaluates the relevance of representing relative permeability variations in the sealing formation when modelling geological CO2 sequestration processes. Here we concentrate on gradational changes in the lower part of the caprock, particularly how they affect pressure evolution within the entire sealing formation when duly represented by relative permeability functions. The results demonstrate the importance of accounting for pore size variations in the mathematical model adopted to generate the characteristic curves for GCS analysis. Gradational changes at the base of the caprock influence the magnitude of pressure that propagates vertically into the caprock from the aquifer, especially at the critical zone (i.e. the region overlying the CO2 plume accumulating at the reservoir-seal interface). A higher degree of overpressure and CO2 storage capacity was observed at the base of caprocks that showed gradation. These results illustrate the need to obtain reliable relative permeability functions for GCS, beyond just permeability and porosity data. The study provides a formative principle for geomechanical simulations that study the possibility of pressure-induced caprock failure during CO2 sequestration

Forecasting CO2 Sequestration with Enhanced Oil Recovery

The aim of carbon capture, utilization, and storage (CCUS) is to reduce the amount of CO2 released into the atmosphere and to mitigate its effects on climate change. Over the years, naturally occurring CO2 sources have been utilized in enhanced oil recovery (EOR) projects in the United States. This has presented an opportunity to supplement and gradually replace the high demand for natural CO2 sources with anthropogenic sources. There also exist incentives for operators to become involved in the storage of anthropogenic CO2 within partially depleted reservoirs, in addition to the incremental production oil revenues. These incentives include a wider availability of anthropogenic sources, the reduction of emissions to meet regulatory requirements, tax incentives in some jurisdictions, and favorable public relations. The United States Department of Energy has sponsored several Regional Carbon Sequestration Partnerships (RCSPs) through its Carbon Storage program which have conducted field demonstrations for both EOR and saline aquifer storage. Various research efforts have been made in the area of reservoir characterization, monitoring, verification and accounting, simulation, and risk assessment to ascertain long-term storage potential within the subject storage complex. This book is a collection of lessons learned through the RCSP program within the Southwest Region of the United States. The scope of the book includes site characterization, storage modeling, monitoring verification reporting (MRV), risk assessment and international case studies

Carbon dioxide storage in the UK southern north sea: experimental and numerical analysis

This thesis contributes to the significant portfolio of research on carbon capture and storage (CCS) in general, and the potential for CO₂ storage with impurities within the UK Southern North Sea (UKSNS) to meet the global greenhouse gas emission reduction targets. First, this thesis extensively reviews the current developments in carbon dioxide storage, highlighting major options for CO₂ sequestration, storage site evaluation criteria, behaviour of CO₂ in the reservoir, methodologies for estimating storage capacity, appraisal of the major storage projects, and a projection of the future outlook for CO₂ storage. The review draws attention to the fact that although a high-quality knowledge base has been developed through CCS research, the main hinderance to CO₂ storage deployment is associated with public acceptability of the technology. Second, this thesis involves laboratory experimental investigation of the effect of impure CO₂ on reservoir grain size distributions and permeability using rock samples from the Bunter saline aquifer. The thesis shows that the presence of impurities in the CO₂ stream can affect the grain size distribution and fluid transmissivity. Third, this thesis uses numerical modelling to evaluate the effect of impure CO₂ on reservoir performance with a case study from the Bunter saline aquifer. The results show that depending on the impurities present in the CO₂ stream, the limits of stability during storage operations in saline aquifer varies, however, the variation does not affect reservoir performance negatively during long-term injection and storage

Diagenesis and Formation Stress in Fracture Conductivity of Shaly Rocks; Experimental-Modelling Approach in CO2-Rock Interactions

In large scale subsurface injection of carbon dioxide (CO2) as obtainable in carbon sequestration programs and in environmentally friendly hydraulic fracturing processes (using supercritical CO2), long term rock-fluid interaction can affect reservoir and seal rocks properties which are essential in monitoring the progress of these operations. The mineralogical components of sedimentary rocks are geochemically active particularly under enormous earth stresses, which generate high pressure and temperature conditions in the subsurface. While geomechanical properties such as rock stiffness, Poisson’s ratio and fracture geometry largely govern fluid flow characteristics in deep fractured formations, the effect of mineralization can lead to flow impedance in the presence of favorable geochemical and thermodynamic conditions. Simulation results suggested that influx-induced mineral dissolution/precipitation reactions within clay-based sedimentary rocks can continuously close micro-fracture networks, though injection pressure and effective-stress transformation first rapidly expand the fractures. This experimental modelling research investigated the impact of in-situ geochemical precipitation at 50°C and 1,000 psi on conductivity of fractures under geomechanical stress conditions. Geochemical analysis were performed on different samples of shale rocks, effluent fluid and recovered precipitates both before and after CO2-brine flooding of crushed shale rocks at high temperature and pressure conditions. Bulk rock geomechanical hardness was determined using micro-indentation. Differential pressure drop data across fractured composite core were also measured with respect to time over a five a day period. This was used in estimating the conductivity of the fractured core. Three experimental runs per sample type were carried out in order to check the validity of observed changes. The results showed that most significant diagenetic changes in shale rocks after flooding with CO2-brine reflect in the effluent fluid with calcium based minerals dissolving and precipitating under experimental conditions. Major and trace elements in the effluent fluid (using ICP-OES analysis) indicated that multiple geochemical reactions are occurring with almost all of the constituent minerals participating. The geochemical composition of precipitates recovered after the experiments showed diagenetic carbonates and opal (quartz) as the main constituents. The bulk rock showed little changes in composition except for sharper peaks on XRD analysis, suggesting that a significant portion of amorphous content of the rocks have been removed via dissolution by the slightly acid CO2-brine fluid that was injected. However total carbon (TOC) analysis showed a slight increase in carbon content of the bulk rock. Micro-indention results suggested a slight reduction in the hardness of the shale rocks and this reduction appear dependent on quartz content. The differential pressure drop, its 1st derivative and estimated fracture conductivity suggests that reactive transport of dissolved minerals can possibly occlude fracture flow path at varying degree depending on equivalent aperture width, thereby improving caprock integrity with respect to leakage risks under CO2 sequestration conditions. An exponential-natural logarithm fit of the fracture conductivity can be obtained and applied in discrete fracture network modelling. The fit yielded lower and upper boundary limits for fracture conductivity closure. Higher temperature and pressure conditions of experimental investigations may be needed to determine the upper limit of shale rock seal integrity tolerance, under conditions that are similar to sequestration of CO2 into deep and hot sedimentary rocks

A review of developments in carbon dioxide storage

Carbon capture and storage (CCS) has been identified as an urgent, strategic and essential approach to reduce anthropogenic CO2 emissions, and mitigate the severe consequences of climate change. CO2 storage is the last step in the CCS chain and can be implemented mainly through oceanic and underground geological sequestration, and mineral carbonation. This review paper aims to provide state-of-the-art developments in CO2 storage. The review initially discussed the potential options for CO2 storage by highlighting the present status, current challenges and uncertainties associated with further deployment of established approaches (such as storage in saline aquifers and depleted oil and gas reservoirs) and feasibility demonstration of relatively newer storage concepts (such as hydrate storage and CO2-based enhanced geothermal systems). The second part of the review outlined the critical criteria that are necessary for storage site selection, including geological, geothermal, geohazards, hydrodynamic, basin maturity, and economic, societal and environmental factors. In the third section, the focus was on identification of CO2 behaviour within the reservoir during and after injection, namely injection-induced seismicity, potential leakage pathways, and long-term containment complexities associated with CO2-brine-rock interaction. In addition, a detailed review on storage capacity estimation methods based on different geological media and trapping mechanisms was provided. Finally, an overview of major CO2 storage projects, including their overall outcomes, were outlined. This review indicates that although CO2 storage is a technically proven strategy, the discussed challenges need to be addressed in order to accelerate the deployment of the technology. In addition, beside the necessity of techno-economic aspects, public acceptance of CO2 storage plays a central role in technology deployment, and the current ethical mechanisms need to be further improved

Hydrogen storage in depleted gas reservoirs: A comprehensive review

Hydrogen future depends on large-scale storage, which can be provided by geological formations (such as caverns, aquifers, and depleted oil and gas reservoirs) to handle demand and supply changes, a typical hysteresis of most renewable energy sources. Amongst them, depleted natural gas reservoirs are the most cost-effective and secure solutions due to their wide geographic distribution, proven surface facilities, and less ambiguous site evaluation. They also require less cushion gas as the native residual gases serve as a buffer for pressure maintenance during storage. However, there is a lack of thorough understanding of this technology. This work aims to provide a comprehensive insight and technical outlook into hydrogen storage in depleted gas reservoirs. It briefly discusses the operating and potential facilities, case studies, and the thermophysical and petrophysical properties of storage and withdrawal capacity, gas immobilization, and efficient gas containment. Furthermore, a comparative approach to hydrogen, methane, and carbon dioxide with respect to well integrity during gas storage has been highlighted. A summary of the key findings, challenges, and prospects has also been reported. Based on the review, hydrodynamics, geochemical, and microbial factors are the subsurface\u27s principal promoters of hydrogen losses. The injection strategy, reservoir features, quality, and operational parameters significantly impact gas storage in depleted reservoirs. Future works (experimental and simulation) were recommended to focus on the hydrodynamics and geomechanics aspects related to migration, mixing, and dispersion for improved recovery. Overall, this review provides a streamlined insight into hydrogen storage in depleted gas reservoirs

CO2 storage in depleted oil and gas reservoirs: A review

Geological storage of CO2 in depleted oil and gas reservoirs is approved due to its advantages, such as strong storage capacity, good sealing performance, and complete infrastructure. This review clarified the existing projects, advantages, significances, influencing factors, mechanisms, and storage potential evaluation procedures of CO2 storage in depleted oil and gas reservoirs. In this review, the storage capability of depleted oil and gas reservoirs has been confirmed, and factors affecting the CO2 storage potential, including geological factors and engineering factors, are concluded. CO2 trapping mechanisms of different storage processes in depleted oil and gas reservoirs are elaborated and divided into three stages. The evaluation stages of CO2 storage potential of depleted oil and gas reservoirs are summarized as basin selection evaluation stage, oil and gas reservoir selection evaluation stage, storage security evaluation using the bowtie method, and storage capacity calculation stage. The calculation accuracy of CO2 storage capacity in depleted oil and gas reservoirs can be optimized by determining the mineralization storage volume and the actual reservoir characteristics of the dissolution storage coefficient numerically. This work intends to provide support for the storage of CO2 by analyzing and studying the geological theory and engineering achievements of CO2 storage in depleted oil and gas reservoirs.Document Type: Invited reviewCited as: Wei, B., Wang, B., Li, X., Aishan, M., Ju, Y. CO2 storage in depleted oil and gas reservoirs: A review. Advances in Geo-Energy Research, 2023, 9(2): 76-93. https://doi.org/10.46690/ager.2023.08.0

Pore-Scale and Conventional Wettability Measurement Considerations for Improving Certainty of Geological CO2 Sequestration

Parallel to the approach of developing zero-carbon-emission energies, other solutions have been recently proposed to decrease the amount of CO2 emissions into the atmosphere. Geological CO2 sequestration (GCS) has provided economic benefits and slight adverse environmental effects. GCS involves capturing CO2 from large producers, then injecting it into deep layers of the earth’s subsurface to be stored for hundreds to thousands of years. A safe and economic GCS requires a profound knowledge of immiscible CO2-water/brine fluid flow in CO2 storage sites including capillary pressure which has a barrier effect against leakage. The main uncertainty in measuring capillary pressure is due to the wettability, which is quantified by contact angle of water/brine interface on rock surface. The objective of this study is to explore the reasons of uncertainty observed in conventional contact angle measurement and introduce a more realistic pore level contact angle measurement. The contact angle of water/brine on select minerals found in common rocks (silica and mica) was measured using a high-pressure, high-temperature chamber developed for a captive bubble test method. As an innovative method, pore-scale static and dynamic contact angles were also measured inside a high-pressure micromodel using a microscope. The results showed that the heterogeneity on minerals surface plays an important role in controlling contact angle variation with time. With unsaturated fluid (water/brine-CO2) condition, which is more realistic in the short-term after CO2 injection, the contact angle can increase due to a pinned triple line (the line on which the three phases of the liquid, gaseous, and solid surface meet) as a result of heterogeneity. An increased contact angle causes the capillary pressure to decrease resulting in a higher leakage risk. The micro-scale dynamic contact angle results showed that rocks were not as water-wet as assumed in literature when conventional measurement methods on flat surfaces of minerals were used. An increase of pressure and salinity changed the glass (silica) behavior from water-wet to intermediate-wet. Pore-scale contact angle measurement provides more realistic wettability behavior of geo-materials and increases the certainty the simulations used for assessing safety and efficiency of storage sites