Evolution of sealing efficiency for CO2 geological storage due to mineral alteration within a hydrogeologically heterogeneous caprock

In CO₂ geological storage (CGS) context, the evolution of the caprock sealing capacity has received increasing attention, particularly on a geological time span (thousands of years). At this time scale, geochemical reactions may enhance or weaken the caprock quality. It is widely recognized that, for the reservoir, geological heterogeneities affect the concentration and spatial distribution of CO₂, and then affect the extent of gas–water–rock interactions, which in turn alters the hydrogeological properties of the reservoir. However, much less attention of these effects has been paid to the caprock. In this study, we presented and applied a novel approach to evaluate the effects of permeability and porosity heterogeneities on the alteration of minerals, the associated evolution of the caprock sealing efficiency and the containment of supercritical CO₂ (scCO₂) within the caprock. Even though this is a generic study, several conditions and parameters such as pressure, permeability, and mineral composition, were extracted from a caprock layer of the Shiqianfeng Formation in the Ordos Basin demonstration site in China. For the sake of simplification, a 2-dimensional model was designed to represent the caprock domain. We firstly generated an appropriate heterogeneous random field of permeability with the average permeability taken from the uppermost mudstone layer of the Shiqianfeng Formation, and then the heterogeneity in porosity was incorporated using a joint normal distribution method based on the available data. Homogeneous mineral compositions of the reservoir and caprock were used in all simulations. Simulations of three cases were performed, including a homogeneous case, a case with only permeability heterogeneity and a case with both permeability and porosity heterogeneities. The results demonstrate dramatic influences of permeability and porosity heterogeneities on the migration of scCO₂ within the caprock, the alteration of minerals, and therefore the evolution of the caprock sealing quality. Specific to the data used in this study, hydrogeological heterogeneities facilitated the overall penetration of scCO₂ within the caprock and promoted the alteration of minerals, thereby weakening the caprock sealing efficiency over the simulation time.     

Experimental investigation into the sealing capability of naturally fractured shale caprocks to supercritical carbon dioxide flow

Geological storage of CO₂ is considered a solution for reducing the excess CO₂ released into the atmosphere. Low permeability caprocks physically trap CO₂ injected into underlying porous reservoirs. Injection leads to increasing pore pressure and reduced effective stress, increasing the likelihood of exceeding the capillary entry pressure of the caprocks and of caprock fracturing. Assessing on how the different phases of CO₂ flow through caprock matrix and fractures is important for assessing CO₂ storage security. Fractures are considered to represent preferential flow paths in the caprock for the escape of CO₂. Here we present a new experimental rig which allows 38 mm diameter fractured caprock samples recovered from depths of up to 4 km to be exposed to supercritical CO₂ (scCO₂) under in situ conditions of pressure, temperature and geochemistry. In contrast to expectations, the results indicate that scCO₂ will not flow through tight natural caprock fractures, even with a differential pressure across the fractured sample in excess of 51 MPa. However, below the critical point where CO₂ enters its gas phase, the CO₂ flows readily through the caprock fractures. This indicates the possibility of a critical threshold of fracture aperture size which controls CO₂ flow along the fracture.     

Determining effective wellbore permeability from a field pressure test: a numerical analysis of detection limits

We propose a simple pressure test that can be used in the field to determine the effective permeability of existing wellbores. Such tests are motivated by the need to understand and quantify leakage risks associated with geological storage of CO₂ in mature sedimentary basins. If CO₂ is injected into a deep geological formation, and the resulting CO₂ plume encounters a wellbore, leakage may occur through various pathways in the “disturbed zone” surrounding the well casing. The effective permeability of this composite zone, on the outside of the well casing, is an important parameter for models of leakage. However, the data that exist on this key parameter do not exist in the open literature, and therefore specific field tests need to be done in order to reduce the uncertainty inherent in the leakage estimates. The test designed and analyzed herein is designed to measure effective wellbore permeability within a low-permeability caprock, bounded above and below by permeable reservoirs, by pressurizing the reservoir below and measuring the response in the reservoir above. Alternatively, a modified test can be performed within the caprock without directly contacting the reservoirs above and below. We use numerical simulation to relate pressure response to effective well permeability and then evaluate the range of detection of the effective permeability based on instrument measurement error and limits on fracture pressure. These results can guide field experiments associated with site characterization and leakage analysis.     

A numerical study of mineral alteration and self-sealing efficiency of a caprock for CO2 geological storage

Geochemical interactions of brine–rock–gas have a significant impact on the stability and integrity of the caprock for long-term CO₂ geological storage. Invasion of CO₂ into the caprock from the storage reservoir by (1) molecular diffusion of dissolved CO₂, (2) CO₂-water two-phase flow after capillary breakthrough, and (3) CO₂ flow through existing open fractures may alter the mineralogy, porosity, and mechanical strength of the caprock due to the mineral dissolution or precipitation. This determines the self-enhancement or self-sealing efficiency of the caprock. In this paper, two types of caprock, a clay-rich shale and a mudstone, are considered for the modeling analyses of the self-sealing and self-enhancement phenomena. The clay-rich shale taken from the Jianghan Basin of China is used as the base-case model. The results are compared with a mudstone caprock which is compositionally very different than the clay-rich shale. We focus on mineral alterations induced by the invasion of CO₂, feedback on medium properties such as porosity, and the self-sealing efficiency of the caprock. A number of sensitivity simulations are performed using the multiphase reactive transport code TOUGHREACT to identify the major minerals that have an impact on the caprock’s self-sealing efficiency. Our model results indicate that under the same hydrogeological conditions, the mudstone is more suitable to be used as a caprock. The sealing distances are barely different in the two types of caprock, both being about 0.6 m far from the interface between the reservoir and caprock. However, the times of occurrence of sealing are considerably different. For the mudstone model, the self-sealing occurs at the beginning of simulation, while for the clay-rich shale model, the porosity begins to decline only after 100 years. At the bottom of the clay-rich shale column, the porosity declines to 0.034, while that of mudstone declines to 0.02. The sensitive minerals in the clay-rich shale model are calcite, magnesite, and smectite-Ca. Anhydrite and illite provide Ca²⁺ and Mg²⁺ to the sensitive minerals for their precipitation. The mudstone model simulation is divided into three stages. There are different governing minerals in different stages, and the effect of the reservoir formation water on the alteration of sensitive minerals is significant.     

Chemical effects of sulfur dioxide co-injection with carbon dioxide on the reservoir and caprock mineralogy and permeability in depleted gas fields

The most suitable candidates for subsurface storage of CO₂ are depleted gas fields. Their ability to retain CO₂ can however be influenced by the effect which impurities in the CO₂ stream (e.g. H₂S and SO₂) have on the mineralogy of reservoir and seal. In order to investigate the effects of SO₂ we carried out laboratory experiments on reservoir and cap rock core samples from gas fields in the northeast of the Netherlands. The rock samples were contained in reactor vessels for 30 days in contact with CO₂ and 100 ppm SO₂ under in-situ conditions (300 bar, 100 °C). The vessels also contained brine with the same composition as in the actual reservoir. Furthermore equilibrium modeling was carried out using PHREEQC software in order to model the experiments on caprock samples.After the experiments the permeability of the reservoir samples had increased by a factor of 1.2–2.2 as a result of dissolution of primary reservoir minerals. Analysis of the associated brine samples before and after the experiments showed that concentrations of K, Si and Al had increased, indicative of silicate mineral dissolution.In the caprock samples, composed of carbonate and anhydrite minerals, permeability changed by a factor of 0.79–23. The increase in permeability is proportional to the amount of carbonate in the caprock. With higher carbonate content in comparison with anhydrite the permeability increase is higher due to the additional carbonate dissolution. This dependency of permeability variations was verified by the modeling study. Hence, caprock with a higher anhydrite content in comparison with carbonate minerals has a lower risk of leakage after co-injection of 100 ppmv SO₂ with CO₂.     

Numerical modelling of the hydro‐chemo‐mechanical behaviour of geomaterials in the context of CO2 injection

Safety assessment of geosequestration of CO₂ into deep saline aquifers requires a precise understanding of the study of hydro‐chemo‐mechanical couplings occurring in the rocks and the cement well. To this aim, a coupled chemo‐poromechanical model has been developed and implemented into a research code well‐suited to the resolution of fully coupled problems. This code is based on the finite volume methods. In a 1D axisymmetrical configuration, this study aims to simulate the chemo‐poromechanical behaviour of a system composed by the cement well and the caprock during CO₂ injection. Major chemical reactions of carbonation occurring into cement paste and rocks are considered in order to evaluate the consequences of the presence of CO₂ on the amount of dissolved matrix and precipitated calcium carbonates. The dissolution of the solid matrix is taken into account through the use of a chemical porosity. Matrix leaching and carbonation lead, as expected, to important variations of porosity, permeability and to alterations of transport properties and mechanical stiffness. These results justify the importance of considering a coupled analysis accounting for the main chemical reactions. It is worth noting that the modelling framework proposed in the present study could be extended to model the chemo‐poromechanical behaviour of the reservoir rock and the caprock when subjected to the presence of an acidic pore fluid (CO₂‐rich brine). Copyright © 2013 John Wiley & Sons, Ltd.     

深部咸水层二氧化碳地质储存场地选址储盖层评价

深部咸水层CO2地质储存属于环保型工程项目,开展地质评价来确定良好的储盖层是实现CO2地质储存长期、有效、安全封存的首要前提。储层地质评价内容主要包括储层的物理性质及其注入能力等;盖层地质评价内容主要包括盖层发育特征及封闭能力等。在规划选址到工程选址的不同阶段,储盖层评价的内容和对象应根据不同阶段的目的依次提高精度和量化程度。通过国内深部咸水层CO2地质储存工程场地选址阶段划分,结合储盖层地质评价的主要内容,初步建立了储盖层适宜性评价指标及其分级标准,对国内深部咸水层CO2地质储存工程场地选址中的储盖层地质评价及适宜性评价工作具有一定的指导意义。     

Seal integrity and feasibility of CO<Subscript>2</Subscript> sequestration in the Teapot Dome EOR pilot: geomechanical site characterization

This paper reports a preliminary investigation of CO₂ sequestration and seal integrity at Teapot Dome oil field, Wyoming, USA, with the objective of predicting the potential risk of CO₂ leakage along reservoir-bounding faults. CO₂ injection into reservoirs creates anomalously high pore pressure at the top of the reservoir that could potentially hydraulically fracture the caprock or trigger slip on reservoir-bounding faults. The Tensleep Formation, a Pennsylvanian age eolian sandstone is evaluated as the target horizon for a pilot CO₂ EOR-carbon storage experiment, in a three-way closure trap against a bounding fault, termed the S1 fault. A preliminary geomechanical model of the Tensleep Formation has been developed to evaluate the potential for CO₂ injection inducing slip on the S1 fault and thus threatening seal integrity. Uncertainties in the stress tensor and fault geometry have been incorporated into the analysis using Monte Carlo simulation. The authors find that even the most pessimistic risk scenario would require ∼10 MPa of excess pressure to cause the S1 fault to reactivate and provide a potential leakage pathway. This would correspond to a CO₂ column height of ∼1,500 m, whereas the structural closure of the Tensleep Formation in the pilot injection area does not exceed 100 m. It is therefore apparent that CO₂ injection is not likely to compromise the S1 fault stability. Better constraint of the least principal stress is needed to establish a more reliable estimate of the maximum reservoir pressure required to hydrofracture the caprock.     

Non-parametric simulations-based conditional stochastic predictions of geologic heterogeneities and leakage potentials for hypothetical CO2 sequestration sites

The present study focuses on understanding the leakage potentials of the stored supercritical CO₂ plume through caprocks generated in geostatistically created heterogeneous media. For this purpose, two hypothetical cases with different geostatistical features were developed, and two conditional geostatistical simulation models (i.e., sequential indicator simulation or SISIM and generalized coupled Markov chain or GCMC) were applied for the stochastic characterizations of the heterogeneities. Then, predictive CO₂ plume migration simulations based on stochastic realizations were performed and summarized. In the geostatistical simulations, the results from the GCMC model showed better performance than those of the SISIM model for the strongly non-stationary case, while SISIM models showed reasonable performance for the weakly non-stationary case in terms of low-permeability lenses characterization. In the subsequent predictive simulations of CO₂ plume migration, the observations in the geostatistical simulations were confirmed and the GCMC-based predictions showed underestimations in CO₂ leakage in the stationary case, while the SISIM-based predictions showed considerable overestimations in the non-stationary case. The overall results suggest that: (1) proper characterization of low-permeability layering is significantly important in the prediction of CO₂ plume behavior, especially for the leakage potential of CO₂ and (2) appropriate geostatistical techniques must be selectively employed considering the degree of stationarity of the targeting fields to minimize the uncertainties in the predictions.     

Experimental and numerical investigations on CO2 injection and enhanced gas recovery effects in Altmark gas field (Central Germany)

The feasibility of CO₂ storage and enhanced gas recovery (EGR) effects in the mature Altmark natural gas field in Central Germany has been studied in this paper. The investigations were comprehensive and comprise the characterization of the litho- and diagenetic facies, mineral content, geochemical composition, the petrophysical properties of the reservoir rocks with respect to their potential reactivity to CO₂ as well as reservoir simulation studies to evaluate the CO₂ wellbore injectivity and displacement efficiency of the residual gas by the injected CO₂. The Rotliegend sediments of the Altmark pilot injection area exhibit distinct mineralogical, geochemical, and petrophysical features related to litho- and diagenetic facies types. The reservoir rock reactivity to CO₂ has been studied in autoclave experiments and associated effects on two-phase transport properties have been examined by means of routine and special core analysis before and after the laboratory runs. Dissolution of calcite and anhydrite during the short-term treatments leading to the enhancements of permeability and porosity as well as stabilization of the water saturation relevant for CO₂ injection have been observed. Numerical simulation of the injection process and EGR effects in a sector of the Altmark field coupled with a wellbore model revealed the possibility of injecting the CO₂ gas at temperatures as low as 10 °C and pressures around 40 bar achieving effective inflow in the reservoir without phase transition in the wellbore. The small ratio of injected CO₂ volume versus reservoir volume indicated no significant EGR effects. However, the retention and storage capacity of CO₂ will be maximized. The migration/extension of CO₂ varies as a function of heterogeneity both in the layers and in the reservoir. The investigation of CO₂ extension and pressure propagation suggested no breakthrough of CO₂ at the prospective production well during the 3-year injection period studied.     

Thermo‐hydro‐mechanical modeling with Langmuir's adsorption isotherm of the CO2 injection in coal

In this paper, we used a theoretical model for the variation of Eulerian porosity, which takes into account the adsorption process known to be the main mechanism of production or sequestration of gas in many reservoir of coal. This process is classically modeled using Langmuir's isotherm. After implementation in Code_Aster, a fully coupled thermo‐hydro‐mechanical analysis code for structures calculations, we used numerical simulations to investigate the influence of coal's hydro‐mechanical properties (Biot's coefficient, bulk modulus), Langmuir's adsorption parameters, and the initial liquid pressure in rock mass during CO₂ injection in coal. These simulations showed that the increase in the values of Langmuir's parameters and Biot's coefficient promotes a reduction in porosity because of the adsorption process when the gas pressure increases. Low values of bulk modulus increase the positive effect (i.e., increase) of hydro‐mechanical coupling on the porosity evolution. The presence of high initial liquid pressure in the rock mass prevents the progression of injected gas pressure when CO₂ dissolution in water is taken into account. Copyright © 2014 John Wiley & Sons, Ltd.     

Review: The potential impact of underground geological storage of carbon dioxide in deep saline aquifers on shallow groundwater resources

Underground geological storage of CO₂ in deep saline aquifers is considered for reducing greenhouse gases emissions into the atmosphere. However, some issues were raised with regard to the potential hazards to shallow groundwater resources from CO₂ leakage, brine displacement and pressure build-up. An overview is provided of the current scientific knowledge pertaining to the potential impact on shallow groundwater resources of geological storage of CO₂ in deep saline aquifers, identifying knowledge gaps for which original research opportunities are proposed. Two main impacts are defined and discussed therein: the near-field impact due to the upward vertical migration of free-phase CO₂ to surficial aquifers, and the far-field impact caused by large-scale displacement of formation waters by the injected CO₂. For the near-field, it is found that numerical studies predict possible mobilization of trace elements but concentrations are rarely above the maximum limit for potable water. For the far-field, numerical studies predict only minor impacts except for some specific geological conditions such as high caprock permeability. Despite important knowledge gaps, the possible environmental impacts of geological storage of CO₂ in deep saline aquifers on shallow groundwater resources appears to be low, but much more work is required to evaluate site specific impacts.     

Implications of spatial reservoir uncertainty for CO2 sequestration in the east Snake River Plain, Idaho (USA)

Basalt-hosted hydrogeologic systems have been proposed for geologic CO₂ sequestration based on laboratory research suggesting rapid mineralization rates. However, despite this theoretical appeal, little is known about the impacts of basalt fracture heterogeneity on CO₂ migration at commercial scales. Evaluating the suitability of basalt reservoirs is complicated by incomplete knowledge of in-situ fracture distributions at depths required for CO₂ sequestration. In this work, a numerical experiment is used to investigate the effects of spatial reservoir uncertainty for geologic CO₂ sequestration in the east Snake River Plain, Idaho (USA). Two criteria are investigated: (1) formation injectivity and (2) confinement potential. Several theoretical tools are invoked to develop a field-based approach for geostatistical reservoir characterization and their implementation is illustrated. Geologic CO₂ sequestration is simulated for 10?years of constant-rate injection at ~680,000 tons per year and modeled by Monte Carlo simulation such that model variability is a function of spatial reservoir heterogeneity. Results suggest that the spatial distribution of heterogeneous permeability structures is a controlling influence on formation injectivity. Analysis of confinement potential is less conclusive; however, in the absence of confining sedimentary interbeds within the basalt pile, rapid mineralization may be necessary to reduce the risk of escape.     

An Uncertainty Quantification Framework for Studying the Effect of Spatial Heterogeneity in Reservoir Permeability on CO2 Sequestration

A new uncertainty quantification framework is adopted for carbon sequestration to evaluate the effect of spatial heterogeneity of reservoir permeability on CO₂ migration. Sequential Gaussian simulation is used to generate multiple realizations of permeability fields with various spatial statistical attributes. In order to deal with the computational difficulties, the following ideas/approaches are integrated. First, different efficient sampling approaches (probabilistic collocation, quasi-Monte Carlo, and adaptive sampling) are used to reduce the number of forward calculations, explore effectively the parameter space, and quantify the input uncertainty. Second, a scalable numerical simulator, extreme-scale Subsurface Transport Over Multiple Phases, is adopted as the forward modeling simulator for CO₂ migration. The framework has the capability to quantify input uncertainty, generate exploratory samples effectively, perform scalable numerical simulations, visualize output uncertainty, and evaluate input-output relationships. The framework is demonstrated with a given CO₂ injection scenario in heterogeneous sandstone reservoirs. Results show that geostatistical parameters for permeability have different impacts on CO₂ plume radius: the mean parameter has positive effects at the top layers, but affects the bottom layers negatively. The variance generally has a positive effect on the plume radius at all layers, particularly at middle layers, where the transport of CO₂ is highly influenced by the subsurface heterogeneity structure. The anisotropy ratio has weak impacts on the plume radius, but affects the shape of the CO₂ plume.     

Numerical simulation of carbon dioxide migration in a sandstone aquifer considering the fluid–solid coupling

Very limited investigations have been done on the numerical simulation of carbon dioxide (CO₂) migration in sandstone aquifers taking consideration of the interactions between fluid flow and rock stress. Based on the poroelasticity theory and multiphase flow theory, this study establishes a mathematical model to describe CO₂ migration, coupling the flow and stress fields. Both finite difference method (FDM) and finite element method (FEM) were used to discretize the mathematical model and generate a numerical model. A case study was carried out using the numerical model on the Jiangling sandstone aquifer in the Jianghan basin, China. The rock mechanics parameters of reservoir and overlying strata of Jiangling depression were obtained by triaxial tests. A two-dimensional model was then built to simulate carbon dioxide migration in the sandstone aquifer. The numerical simulation analyzes the carbon dioxide migration distribution rule with and without considering capillary pressure. Time-dependent migration of CO₂ in the sandstone aquifer was analyzed, and the result from the coupled model was compared with that from a traditional non-coupled model. The calculation result indicates a good consistency between the coupled model and the non-coupled model. At the injection point, the CO₂ saturation given by the coupled model is 15.39 % higher than that given by the non-coupled model; while the pore pressure given by the coupled model is 4.8 % lower than that given by the non-coupled model. Therefore, it is necessary to consider the coupling of flow and stress fields while simulating CO₂ migration for CO₂ disposal in sandstone aquifers. The result from the coupled model was also sensitized to several parameters including reservoir permeability, porosity, and CO₂ injection rate. Sensitivity analyses show that CO₂ saturation is increased non-linearly with CO₂ injection rate and decreased non-linearly with reservoir porosity. Pore pressure is decreased non-linearly with reservoir porosity and permeability, and increased non-linearly with CO₂ injection rate. When the capillary pressure was considered, the computed gas saturation of carbon dioxide was increased by 10.75 % and the pore pressure was reduced by 0.615 %.     

Assessment of shrinkage–swelling influences in coal seams using rank-dependent physical coal properties

Characterization of coal reservoirs and determination of in-situ physical coal properties related to transport mechanism are complicated due to having lack of standard procedures in the literature. By considering these difficulties, a new approach has been developed proposing the usage of relationships between coal rank and physical coal properties. In this study, effects of shrinkage and swelling (SS) on total methane recovery at CO₂ breakthrough (TMRB), which includes ten-year primary methane recovery and succeeding enhanced coalbed methane (ECBM) recovery up to CO₂ breakthrough, and CO₂ sequestration have been investigated by using rank-dependent coal properties. In addition to coal rank, different coal reservoir types, molar compositions of injected fluid, and parameters within the extended Palmer & Mansoori (P&M) permeability model were considered. As a result of this study, shrinkage and swelling lead to an increase in TMRB. Moreover, swelling increased CO₂ breakthrough time and decreased displacement ratio and CO₂ storage for all ranks of coal. Low-rank coals are affected more negatively than high-rank coals by swelling. Furthermore, it was realized that dry coal reservoirs are more influenced by swelling than others and saturated wet coals are more suitable for eliminating the negative effects of CO₂ injection. In addition, it was understood that it is possible to reduce swelling effect of CO₂ on cleat permeability by mixing it with N₂ before injection. However, an economical optimization is required for the selection of proper gas mixture. Finally, it is concluded from sensitivity analysis that elastic modulus is the most important parameter, except the initial cleat porosity, controlling SS in the extended P&M model by highly affecting TMRB.     

Petrophysical characterization of the South Georgia Rift Basin for supercritical CO2 storage: a preliminary assessment

The Triassic–Jurassic South Georgia Rift (SGR) Basin, buried beneath Coastal Plain sediments of southern South Carolina, southeastern Georgia, western Florida, and southern Alabama, consists of an assemblage of continental rift deposits (popularly called red beds), and mafic igneous rocks (basalt flows and diabase sills). The red beds are capped by basalts and/or diabase sills, and constitute the target for supercritical CO₂ storage as part of a Department of Energy funded project to study the feasibility for safe and permanent sequestration. The purpose of this research is to evaluate subsurface suitability for underground CO₂ storage in terms of the local and regional distribution of porous and permeable reservoirs. In addition, unlike shale-capped CO₂ reservoirs, very little is known about the ability of basalts and diabase sills to act as viable seals for CO₂ storage. New results demonstrate the presence of confined porous rocks that may be capable of storing significant quantities of supercritical CO₂. Reservoir thicknesses as high as 420 m and an average porosity as high as 14 % were obtained. The SGR Basin manifests distinct porosity–permeability regimes that are influenced by the depositional environments. These are: a high-porosity, medium/low-permeability zone associated with lacustrine deposits, a medium/low-porosity, low-permeability zone dominated by fluvial fine- to very fine-grained sandstone, and an extremely low porosity and permeability zone characterized by fluvial and alluvial-fan deposits. Analyses further show that the basalt flows and diabase sills are characterized by low porosity as well as high seismic velocities and densities that are favorable to caprock integrity.     

Numerical simulation of carbon dioxide injection for enhanced gas recovery (CO2-EGR) in Altmark natural gas field

This paper studied the CO₂-EGR in Altmark natural gas field with numerical simulations. The hydro-mechanical coupled simulations were run using a linked simulator TOUGH2MP-FLAC3D. In order to consider the gas mixing process, EOS7C was implemented in TOUGH2MP. A multi-layered 3D model (4.4 km × 2 km × 1 km) which consists of the whole reservoir, caprock and base rock was generated based on a history-matched PETREL model, originally built by GDF SUEZ E&P Deutschland GmbH for Altmark natural gas field. The model is heterogeneous and discretized into 26,015 grid blocks. In the simulation, 100,000 t CO₂ was injected in the reservoir through well S13 within 2 years, while gas was produced from the well S14. Some sensitivity analyses were also carried out. Simulation results show that CO₂ tends to migrate toward the production well S14 along a NW–SE fault. It reached the observation wells S1 and S16 after 2 years, but no breakthrough occurred in the production well. After 2 years of CO₂ injection, the reservoir pressure increased by 2.5 bar, which is beneficial for gas recovery. The largest uplift (1 mm) occurred at the bottom of the caprock. The deformation was small (elastic) and caprock integrity was not affected. With the injection rate doubled the average pressure increased by 5.3 bar. Even then the CO₂ did not reach the production well S14 after 2 years of injection. It could be concluded that the previous flow field was established during the primary gas production history. This former flow field, including CO₂ injection/CH₄ production rate during CO₂-EGR and fault directions and intensity are the most important factors affecting the CO₂ transport.     

Estimate CO2 storage capacity of the Johansen formation: numerical investigations beyond the benchmarking exercise

In this paper, Shell’s in-house reservoir simulator MoReS is applied to a recently introduced CO₂ sequestration benchmark problem entitled “Estimation of the CO₂ Storage Capacity of a Geological Formation” (Class et al. 2008). The principal objective of this benchmark is the simulation of CO₂ distribution within a modeling region, and leakage of CO₂ outside of it, for a period of 50 years. This study goes beyond the benchmarking exercise to investigate additional factors with direct relevance to CO₂ storage capacity estimations: water and gas relative permeabilities, permeability anisotropy, presence of sub-seismic features (conductive fractures, thin shale layers), regional hydrodynamic gradient, CO₂-enriched brine convection (due to brine density differences), and injection rates. The effects of hydrodynamic gradients and gravitationally induced convection only become significant over 100 s of years. This study has thus extended simulation time to 1,000 years. It is shown that grid resolution significantly impacts results. Vertical-grid refinement results in larger and thinner CO₂ plumes. Lateral-grid refinement delays leakage out of the model domain and reduces injection pressure for a given injection rate. Sub-seismic geological features such as fractures/faults and shale layers are demonstrated to have impact on CO₂ sequestration. Fractures located up-dip from the injector may lead to more leakage while the opposite may happen in the presence of fractures perpendicular to the dip. Thin shale layers produce stacked CO₂ blankets. They should be explicitly represented instead of being upscaled using a reduced vertical to horizontal permeability ratio. Results are seen to be far more sensitive to gas relative permeability and hysteresis than to variations in the water relative permeability models used. For a multi-injectors project, there is scope to optimize the phasing of injections to avoid potential fracturing near injectors.     

Identifying geochemical reactions on wellbore cement/caprock interface under sequestration conditions

The integrity of wells, which are key components for CO₂ sequestration, depends mainly on the seal between the wellbore cement and the geologic formation. To identify the reaction products that may alter the cement/caprock interface, batch experiments and computer modelling were conducted and analysed. Over time, the dissolution and precipitation of minerals alters the physical properties of the interface, including its tightness. One main objective of the simulation was thus to analyse the evolution of the porosity of cement and caprock over time. The alteration of the cement/caprock interface was identified as a complex problem and differentiated depending on rock type. The characteristic feature of a cement/shale contact zone is the occurrence of a highly carbonated, compacted layer within the shale, which in turn causes cement/shale detachment. In the case of a cement/anhydrite interface, the most important reaction is severe anhydrite dissolution. Secondary calcite precipitation takes place in deeper parts of the rock. The cement/rock contact zone is prone to rapid mineral dissolution, which contributes to increased porosity and may alter the well integrity. Comparison of computer simulations with autoclave experiments enabled the adjustment of unknown parameters. This enhances the knowledge of these particular assemblages. Overall, a good match was obtained between experiments and simulations, which enhances confidence in using models to predict longer-term evolution.