Caprock Failure Research Articles

Assessment of CO2 storage capacity based on sparse data: Skade Formation

Large North Sea aquifers of high quality are the likely major target for 12 Gt of European CO2 emissions that should be stored in the subsurface by 2050. This involves an upscaling of the present combined injection rate from all European projects, which requires careful examination of the storage feasibility. Many aquifers are closed or semi-closed, with storage capacity mainly constrained by consideration of caprock failure criteria. Because the induced overpressure can propagate to sensitive regions far from the injector, the risk of caprock failure must be examined in terms of large volumes and for long times. This poses challenges with respect to fluid-flow simulation in the presence of highly uncertain aquifer properties. In this work, experts on geology, geophysics, geomechanics and simulation technique collaborate to optimize the use of existing data in an efficient simulation framework. The workflow is applied to the large North Sea Skade Formation, with potential for secondary storage and pressure dissipation in the overlying Utsira Formation. Injection at three locations in Skade gives an overall practical capacity of 1–6 Gt CO2 injected over a 50-year period, depending on the reservoir permeability and compressibility. The capacity is limited by local pressure buildup around wells for the lowest estimated reservoir permeability, and otherwise by regional pressure buildup in shallow zones far from the injection sites. Local deformation of clay due to viscoelastoplastic effects do not have an impact on leakage from the aquifer, but these effects may modify the properties of clay layers within the aquifer, which reduces the risk of lateral compartmentalization. Uplift of the seafloor does not impose constraints on the capacity beyond those set by pressure buildup.

Coupled Geomechanical‐Flow Assessment of CO2 Leakage through Heterogeneous Caprock during CCS

The viability of carbon capture sequestration (CCS) is dependent on the secure storage of CO2 in subsurface geologic formations. Geomechanical failure of caprock is one of the main reasons of CO2 leakage from the storage formations. Through comprehensive assessment on the petrophysical and geomechanical heterogeneities of caprock, it is possible to predict the risk of unexpected caprock failure. To describe the fracture reactivation, the modified Barton–Bandis model is applied. In order to generate hydro‐geomechanically heterogeneous fields, the negative correlation between porosity and Young’s modulus/Poisson’s ratio is applied. In comparison with the homogeneous model, effects of heterogeneity are examined in terms of vertical deformation and the amount of leaked CO2. To compare the effects of heterogeneity, heterogeneous models for both geomechanical and petrophysical properties in coupled simulation are designed. After 10‐year injection with petrophysically heterogeneous and geomechanically homogeneous caprock, CO2 leakage is larger than that of the homogeneous model. In contrast, heterogeneity of geomechanical properties is shown to mitigate additional escape of CO2. Vertical displacement of every heterogeneous model is larger than homogeneous model. The model with compressive tectonic stress shows much more stable trapping with heterogeneous caprock, but there is possibility of rapid leakage after homogeneous caprock failure.

CO2 Sequestration Safety Monitoring by using Seismic Imaging and Double Difference Tomography

Shale gas has become an increasingly important clean energy, which has been explored worldwide in recent decades. In the shale gas production, supercritical CO 2 acts as a fracturing fluid. For preventing any kinds of leakage of the injected supercritical CO 2 , it is essential to monitor the stability of its storage hundreds of kilometres beneath the Earth’s surface. Seismic tomography is an imaging technique that uses induced seismic waves to create three dimensional images of the subsurface. It is an effective monitoring method to evaluate the caprock integrity in the CO 2 sequestration storage (CCS). In this experimental research, a simulated uniaxial compressive load was applied on a granite sample to analyze the stress redistribution for long-term in-situ caprock integrity during CO 2 injection. The induced seismic waves were recorded, and seismic events were located according to the Geiger algorithm. The frequency of seismic events correlates with the caprock failure evolution. Based on the frequency of seismic events and the failure process, the seismic data is divided into four regimes to examine the failure evolution. Finally, the double difference tomography (TomoDD) algorithm using arrival time was adopted to recalculate to modify the locations of seismic events and velocity structure in each regime. The results indicate that the passive seismic system can map the caprock stress distribution and allow for imaging of the caprock integrity. TomoDD exhibits sound improvements to relocate seismic events both in relative and absolute locations as well as to characterize the local velocity structure. The study further reveals that seismic monitoring along with TomoDD could evaluate the caprock failure accurately in the CCS.

Coupled Thermo-hydro-Mechanical Effects on Caprock Stability During Carbon Dioxide Injection

This study presents a numerical investigation of the effects of coupled material properties on the caprock stability. A thermo-hydro-mechanical framework is proposed in order to reproduce the physical processes. The results indicate that for a given geometrical configuration and a given temperature difference between injected CO2 and reservoir, the potential for the caprock failure may increase or decrease. This contradictory behaviour mainly depends on the combination of the thermal-hydro-mechanical parameters, i.e., thermal expansion coefficient, stiffness and the Biot coefficient. Therefore, the coupled effects of material properties on the caprock stability should be addressed in a combined way for low-temperature CO2 injection problems.

Seismic interpretation and characterization of anhydrite caprocks in the Tromsø Basin, SW Barents Sea

The origin of anhydrite caprocks found in many evaporite basins is currently under debate. Existing models in the literature for anhydrite formation include rotated stratigraphic layering, rotated crestal caprock and diagenetic anhydrite. In this work, we interpret high-quality 2D seismic reflection data to understand the processes associated with anhydrite caprock formation. Our study focuses on anhydrite caprock formation in the Tromsø Basin, which represents one of several underexplored salt basins in the Arctic. We use well log data and seismic stratigraphic as well as seismic attribute analyses to characterize the ‘anhydrite’ layers associated with salt diapirs. Our results reveal that the anhydrite layers are high-amplitude reflections at the crests, which are often found close to the seabed and lateral caprocks on the flanks of salt diapirs. A third class of anhydrite layers is folded, faulted and boudinaged intrasalt stringers encased by the salt diapirs. Lateral caprocks in the Tromsø Basin are formed in response to rotated crestal caprock failure. The crestal caprocks are secondary in origin, occur at shallow depths, and are formed as insoluble residues from the dissolution of halite by the ingress of basinal fluids into the tops of diapirs. Anhydrite stringers, or floaters, originate from tectonic-related multi-dimensional salt flow. Salt diapirs in the Tromsø Basin are associated with varied anhydrite caprocks; their formation cannot be fully explained using a single model. Our work demonstrates from seismic reflection data the occurrence of caprock events that formed progressively on the flanks of salt diapirs due to local folding.

Monitoring of Rock Stress Redistribution in Geological CO2 Sequestration

Shale gas has become an increasingly important clean energy, which has been explored worldwide in recent decades. Supercritical CO 2 acts as fracturing fluid for shale gas production. The safety monitoring is essential to prevent any kinds of leakage from the reservoir as the supercritical CO 2 physically stored hundred kilometres underground. Seismic tomography is an imaging technique that uses induced seismic waves to create three dimensional images of the subsurface. It is an effective monitoring method to evaluate the caprock integrity in the carbon dioxide sequestration storage (CCS). In this experimental research, a simulated uniaxial compressive load is applied on a granite sample to analyze the stress redistribution for long-term in-situ caprock integrity during CO 2 injection. The induced seismic waves are recorded and seismic events are traced based on the Geiger algorithm. The frequency of seismic events correlates with the caprock failure evolution. The acquired seismic data is divided into four regimes based on the frequency of seismic events and the failure process to examine the failure evolution. Furthermore, the travel time and distance is plotted to analyze the variation of velocity. Finally, the double difference tomography (TomoDD) algorithm using arrival time is adopted to recalculate the locations of seismic events and velocity structure in each regime. The results indicate that the passive seismic system can map the caprock stress distribution and allow for imaging of the caprock integrity. TomoDD exhibits sound improvements to relocate seismic events both in relative and absolute locations as well as to characterize the local velocity structure. The study further reveals that seismic monitoring along with TomoDD could evaluate the caprock failure accurately in the CCS.

Numerical assessment of the maximum operating pressure for SAGD projects by considering the intrinsic shale anisotropy

This paper investigates the effect of anisotropic behavior of caprock shales on the caprock failure pressure in SAGD projects. Shales and mudstones exhibit strong anisotropy at the micro and macro scales. However, the anisotropic behavior has been neglected in the existing published works on this subject. This paper focuses on the effect of the intrinsic anisotropy of shales on caprock integrity. The Maximum Operating Pressure (MOP) is calculated from the failure pressure using an appropriate safety factor.In this paper, a coupled hydro-thermo-mechanical model was developed for the assessment of caprock integrity in thermal operations. A transversely isotropic constitutive model in the elastic range was combined with an anisotropic failure criterion to capture the intrinsic anisotropy of the cap shale. The coupled tool was validated against field data (mainly the surface heave) and employed in a study to determine the effect of shale anisotropic behavior on the pressure associated with caprock breach.Results display the effect of shale anisotropy on caprock response in terms of deformations, stresses and failure pressure. The assumption of isotropic shale behavior in caprock integrity assessment for a case study resulted in the overestimation of the failure pressure by about 7%.Existing numerical models for evaluating the integrity of caprocks during thermal operations employ isotropic constitutive laws. These models are believed to be deficient in capturing strongly anisotropic response of shales and mudstones. The research described in this paper incorporated elasto-plastic shale anisotropy in the caprock failure analysis model for the first time. This study demonstrates the importance of capturing shale anisotropy in the accurate prediction of caprock breach pressure in SAGD projects.

Risking fault reactivation induced by gas injection into depleted reservoirs based on the heterogeneity of geomechanical properties of fault zones

Predictions of fault reactivation and the hydraulic seal of cap rock are integral parts of the seal integrity research programme of the Banzhongbei gas storage facility (BGS) to ensure the safe storage of natural gas in subsurface reservoirs. We attempt to combine the heterogeneity of geomechanical properties, including frictional coefficient and cohesive strength, into a workflow to estimate fault reactivation risk and the maximum sustainable fluid pressure that will not induce failure of trap-bounding faults and cap rock. Based on the Griffith – Coulomb Failure criterion, fault failure modes – including tensile failure, shear failure and hybrid failure – may occur under conditions of the same in situ stress field as a result of the strength heterogeneity of fault rocks, which plays a key role in the estimation of integrity of the entire fault trap. The juxtaposition of the seal on the BQ Fault with high shale gouge ratio (SGR) values makes a significant contribution to the high fluid pressure build-ups during gas injection, and its low strength properties lead to a higher reactivation risk for the Banqiao (BQ) Fault than for the B816 Fault. The increased pore-fluid pressure adjacent to the BQ Fault induced by gas injection should be lower than 9.7 MPa in order to avoid failure. Furthermore, the maximum sustainable fluid pressure of the cap rock is approximately 13.9 MPa at the locations of the injection wells.

Opportunities for increasing CO2 storage in deep, saline formations by active reservoir management and treatment of extracted formation water: Case study at the GreenGen IGCC facility, Tianjin, PR China

Carbon capture, utilization and storage (CCUS) seeks beneficial applications for CO2 recovered from fossil fuel combustion. This study evaluated the potential for removing formation water to create additional storage capacity for CO2, while simultaneously treating the produced water for beneficial use. The process would control pressures within the target formation, lessen the risk of caprock failure, and better control the movement of CO2 within that formation. The project plans to highlight the method of using individual wells to produce formation water prior to injecting CO2 as an efficient means of managing reservoir pressure. Because the pressure drawdown resulting from pre-injection formation water production will inversely correlate with pressure buildup resulting from CO2 injection, it can be proactively used to estimate CO2 storage capacity and to plan well-field operations. The project studied the GreenGen site in Tianjin, China where Huaneng Corporation is capturing CO2 at a coal fired IGCC power plant. Known as the Tianjin Enhanced Water Recovery (EWR) project, local rock units were evaluated for CO2 storage potential and produced water treatment options were then developed. Average treatment cost for produced water with a cooling water treatment goal ranged from 2.27 to 2.96 US$/m3 (recovery 95.25%), and for a boiler water treatment goal ranged from 2.37 to 3.18 US$/m3 (recovery 92.78%). Importance analysis indicated that water quality parameters and transportation are significant cost factors as the injection-extraction system is managed over time. The study found that in a broad sense, active reservoir management in the context of CCUS/EWR is technically feasible. In addition, criteria for evaluating suitable vs. unsuitable reservoir properties, reservoir storage (caprock) integrity, a recommended injection/withdrawal strategy and cost estimates for water treatment and reservoir management are proposed.

Impact of layer thickness and well orientation on caprock integrity for geologic carbon storage

Economic feasibility of geologic carbon storage demands sustaining large storage rates without damaging caprock seals. Reactivation of pre-existing or newly formed fractures may provide a leakage pathway across caprock layers. In this study, we apply an equivalent continuum approach within a finite element framework to model the fluid-pressure-induced reactivation of pre-existing fractures within the caprock, during high-rate injection of super-critical CO2 into a brine-saturated reservoir in a hypothetical system, using realistic geomechanical and fluid properties. We investigate the impact of reservoir to caprock layer thickness, wellbore orientation, and injection rate on overall performance of the system with respect to caprock failure and leakage. We find that vertical wells result in locally higher reservoir pressures relative to horizontal injection wells for the same injection rate, with high pressure inducing caprock leakage along reactivated opening-mode fractures in the caprock. After prolonged injection, leakage along reactivated fractures in the caprock is always higher for vertical than horizontal injection wells. Furthermore, we find that low ratios of reservoir to caprock thickness favor high excess pressure and thus fracture reactivation in the caprock. Injection into thick reservoir units thus lowers the risk associated with CO2 leakage.

Coupled multiphase thermo-hydro-mechanical analysis of supercritical CO2 injection: Benchmark for the In Salah surface uplift problem

CO2 storage in deep aquifers, which is considered one of the most viable technologies, is delivering on its promise of limiting the greenhouse effect. Nevertheless, deep aquifers may experience significant deformation and geomechanical instabilities, such as caprock failure and fault activation, when the deep aquifer is subjected to injection of a large quantity of CO2. The overpressure that arises from this injection usually triggers the onset of these instabilities and deformations. In addition, the temperature of the injected CO2 is often lower than the in-situ temperature, which provides an additional degree of complexity to the system. These complexities are very important to properly assess the associated risks of CO2 storage in a numerical modelling framework that can be used to precisely capture the injection process. In this study, a continuum modelling approach is developed to examine the coupling of thermal, hydraulic and geomechanical processes for CO2 injection into deep aquifers. Numerical simulations are performed with a finite element reservoir model that is built upon available experimental data and real log data for the CO2 storage site at In Salah, Algeria over an injection period of four and a half years. The blind prediction by the fully coupled simulation agrees very well with the real-time monitoring of the surface uplift at In Salah. The thermo-hydro-mechanical responses are also assessed in detail, indicating that both the caprock and aquifer are subjected to high shear failure potential.

Numerical investigation of the formation displacement and caprock integrity in the Ordos Basin (China) during CO2 injection operation

Theoretical and numerical studies of coupled hydro-mechanical processes during geothermal and hydrocarbon production, nuclear waste disposal, and CO2 sequestration in geological media have become a research focus worldwide. However, their application in China, especially CO2 sequestration, is still in infancy and may need several years to develop. In this paper coupled hydro-mechanical processes in CO2 migration, formation uplift and the state of caprock integrity as a result of CO2 sequestration have been investigated by simulation at field scale for an integrated CCS (CO2 Capture and Sequestration) project launched in the Ordos Basin, China. The paper aims at attaining long-term safety and integrity of caprock to ensure success for subsequent project operations at field scale. The linked TOUGH2MP-FLAC3D simulator has been used to study the coupled hydraulic-mechanical responses to primary stresses, injection rate and reservoir permeability during CO2 injection and post-injection periods by means of 4 case studies. In the short-term operation of a CO2 sequestration project launched in the Ordos Basin 0.1Mt CO2 has been injected in four saline aquifers within a period of 1 year and 9 years of relaxation time allotted for simulation runs. Contrary to using hydraulic field conditions alone, a combination of hydraulic-mechanical effects accounts for lateral migration of CO2 in aquifer layers that leads to partial volumetric expansion of the reservoir. Amongst the main factors affecting hydro-mechanical processes, injection rate has the most significant impact. This is followed by reservoir permeability that is responsible for gauging the uplift trend rate in the post-injection period through hindering the dissipation of pore pressure. Results indicate that the scope of pore pressure attained will be larger in the isotropic stress state than in the compressional stress condition, pointing to the significance of primary stress. Calculation of the maximum storage pressure within safety limits using the integrity and shear criteria reveals that failure of caprock integrity increases with the amount of CO2 injected. During injection however, the risk of caprock failure, especially in thin sandstone-caprock interlayered systems, increases with time. This paper estimates the pressure buildup in the four injection aquifers in the Ordos Basin, as a basis to ensure safety in the long-term operation of the CO2 sequestration project, hence providing important reference for future commercial operations at field scale.

Impact indicators for caprock integrity and induced seismicity in CO2 geosequestration: insights from uncertainty analyses

The geological sequestration (geosequestration) of carbon dioxide (CO2) is a mitigation method for reducing greenhouse gas emission into the atmosphere. The security and safety of CO2 geosequestration are strongly dependent on the mechanical stability of the caprock overlying the reservoir. Underground injection of CO2 increases the pore pressure and thus decreases the effective stress. It may lead to caprock failure, as well as the subsequent leakage of sequestered CO2. In particular, geothermal exploitation and the underground disposal of hazardous liquid wastes have demonstrated a risk of induced seismicity. We performed an uncertainty analysis using a novel response surface methodology and a two-step statistical experimental design, evaluated the statistical significance of operator choices and subsurface uncertainties to caprock integrity, and quantified the moment magnitude of the induced seismicity. Furthermore, the optimal combination (i.e., the worst-case scenario) with the desired properties was forecast. A series of numerical experiments was well designed, and 130 combinations were statistically determined. Based on the results from the analysis of variance for the response surface quadratic model, the impact indicators were presented in histograms according to their significances to the Coulomb failure stress and moment magnitude of the induced seismicity. Lastly, the values of the selected independent impact indicators were predicted to obtain optimal compositions for object function of both Coulomb failure stress and moment magnitude, and the desired properties were being picked out. The optimal combinations had desirability values of 1.000, demonstrating the fitness of the selected statistical models in analyzing the experimental data.

Probabilistic geomechanical analysis of compartmentalization at the Snøhvit CO2 sequestration project

AbstractPressure buildup caused by large‐scale CO2 injection is a key concern during a carbon sequestration project. Large overpressures can compromise seal integrity, reactivate faults, and induce seismicity. Furthermore, pressure buildup is directly related with storage capacity. In this work we study the geomechanical response to CO2 injection at Snøhvit, to understand the potential for fault reactivation, leakage, and contamination of the producing interval through bounding faults. Furthermore, we evaluate the potential contribution of a structural component to reservoir compartmentalization. We combine simplified analytical models, based on critically stressed fracture theory and a Mohr‐Coulomb failure criterion, with a rigorous sensitivity analysis. Large stress uncertainties are present and reflected in the modeling results. It was found that under the most likely stress state the faults are fairly stable and caprock hydrofracturing would be expected before fault reactivation. In most of the analyzed cases, the critical pressure perturbation needed for reactivation is above 13 MPa, which was the limiting pressure increase before reaching the fracture pressure. Faults were found to be ~ 20% less stable when considering variations in SHmax orientation. In those cases, fault reactivation could be expected before caprock failure if injection continued. However, if the pressure increase did reach the critical values for seal failure estimated under the worst case (and least likely) stress state, no indication of such failure can be observed in the measured pressure response. Finally, the potential role of a structural component in the compartmentalization and fluid migration is difficult to assess due to the stress state uncertainty.

Investigation of caprock integrity for CO2 sequestration in an oil reservoir using a numerical method

Geological sequestration of carbon dioxide is a mitigation method for reducing greenhouse gas emissions to the atmosphere. Success and safety of a CO2 sequestration operation is strongly dependent on the mechanical stability of the caprock overlying the storage reservoir. Subsurface CO2 injection results in a pore pressure increase and thereby a decrease of the effective stresses, which may lead to caprock failure and subsequent CO2 leakage. In this study, a three-dimensional geomechanical finite element model was built by using Abaqus software to investigate the geomechanical effects of CO2 injection on the caprock and to estimate the risk of caprock failure. The CO2 injection induced pore pressure increase, vertical displacement of the caprock, and the effective stress decrease have been investigated. The results show that the caprock remains stable during the 10-year injection period under the considered conditions. Through quantitative sensitivity analysis, the effects of the input parameters are ranked. CO2 injection rate and initial stress state were found to have the most significant impact on the caprock failure tendency. Results of the numerical model were also validated against analytical solutions.

Fault reactivation case study for probabilistic assessment of carbon dioxide sequestration

This preliminary investigation into carbon dioxide (CO2) sequestration in a Brazilian offshore oil field has the objective of assessing the potential risk of caprock failure for CO2 geological storage in deep aquifers. The technical evaluation of a carbon storage site requires the sustainable pore pressure to be defined. CO2 injection into a hydrocarbon reservoir or aquifer alters the stress locally and also in the surrounding rocks. This brings with it the risk of geological fault reactivation, which would create a likely path for the escape of CO2 to other rock layers, or even to the surface. Several methodologies have been developed to estimate fault reactivation pressures; however, even the most sophisticated solutions depend on data reliability. The aim of this study was to investigate the loss of caprock integrity due to fault reactivation by geological carbon sequestration in a real aquifer using a probabilistic approach that considers the variation of the material properties and the initial stress state. The probabilistic response of the model was evaluated using the integrated nonlinear finite element simulator AEEPEC2D® and NESSUS® probabilistic analysis software. The random variables in the probabilistic model are the average effective vertical stress gradient, elastic modulus, Poisson׳s ratio, the lateral earth pressure coefficient, and the cohesion, friction angle and thickness of the fault. The uncertainties in the properties both rock layers and faults were incorporated into the analysis using the mean value and advanced mean value plus methods. Geomechanical 2D finite element models of the formation were developed to evaluate the stress changes associated with pore pressure variation in cases where an induced fault slippage would be a threat to the integrity of the seal. The proposed methodology was applied to three realistic geological sections with several faults cutting the aquifer. The cumulative distribution curve of maximum admissible pore pressure variation was derived. In addition, the most influential variables for each fault were identified.

Produced-Water-Reinjection Design and Uncertainties Assessment

Summary Produced-water reinjection (PWRI) is an important strategy for deriving value from waste water (Abou Sayed et al. 2005), but its implementation can face challenges related to injectivity and safety issues. Reinjection in a fracturing regime is often the only option to guarantee the sustainability of injectivity (Detienne et al. 2005), but it can present some risks to be anticipated early in the design phase. The first objective of a PWRI-design study is to supply water-quality specifications to petroleum architects (in terms of solid and oil contents) to allow for the design of water-treatment facilities. The second objective is to supply injection-pressure specifications for the design of injection pumps and an injection network. These specifications must allow for sustaining well injectivity over the life of the field, while preventing any risk of caprock failure. The water-quality specification is of prime importance because a maximum of contaminant injection is sought to minimize the cost related to water treatment, but at the same time, it must prevent any injectivity loss or excessive increase of pressure beyond which fracture confinement is no longer possible. Water quality and injection pressure are thus linked to each other. They are deduced by simulation on a case-by-case basis. The modeling approach used by Total was presented in previous publications (Detienne et al. 1998, 2005; Ochi et al. 2007). The objective of this paper is to detail the manner in which the two parameters are deduced when uncertainties on input data are considered. Indeed, a workflow for uncertainty management based on experimental design and Monte Carlo theories was implemented to combine the simultaneous effect of a relatively large number of uncertain parameters, each of them being characterized by its own probabilistic distribution. Two-thousand simulations were run systematically, and water-quality and injection-pressure specifications were supplied with a probabilistic value (P10, P50, and P90). Application of this approach to real-design examples is detailed and discussed in this paper.

The effects of lateral variations in rock composition and texture on anhydrite caprock integrity of CO2 storage systems

We investigated the effect of rock texture and composition on the mechanical strength and volumetric behaviour of anhydrite-rich caprock. Conventional triaxial experiments were performed at 80°C, confining pressures of 1.5–35MPa and strain rates of ~10−5s−1, both dry and in the presence of fluids. We determined the failure envelope, and the effect of fluids upon it, for anhydrite displaying an equigranular texture consisting of euhedral grains. We observed a general pattern of increasing peak compressive strength with increasing confining pressure, consistent with a previous study on anhydrite from the same formation, which showed an irregular texture consisting of interlocking, acicular grains embedded in a fine-grained matrix. The peak strength of euhedral anhydrite was found to be 15–65% lower than that of acicular anhydrite. No chemical effects were observed for the fluids tested. Hydraulic fracturing experiments showed the tensile strength to be approximately 4MPa for euhedral and 6MPa for acicular anhydrite. We combined the failure envelopes with simple, analytical calculations on the effect of cooling on in-situ stress, showing that tensile caprock failure due to cooling would be unlikely for both types of anhydrite, assuming a hypothetical reservoir at a depth of 3800m. However, it should be noted that tensile failure may pose an issue for shallower reservoirs or weaker caprock formations.

Dynamics and design of systems for geological storage of dissolved CO2

The standard approach for geologic storage of CO2 consists of injecting it as a supercritical CO2 phase. This approach places stringent requirements on the caprock, which must display: (1) high entry pressure to prevent the buoyancy driven upwards escape of CO2; (2) low permeability to minimize the upwards flux of brine displaced by the CO2; and (3) high strength to ensure that pressure build up does not cause caprock failure. We propose an alternative approach for cases when the above requirements are not met. The approach consists of extracting brine from the storage formation and then re-injecting it so that it mixes with CO2 at depth in the injection well. Mixing at depth reduces the pressure required for brine and CO2 at the surface. This CO2-saturated brine will sink to the aquifer bottom because it is denser than resident brine, which eliminates the risk of buoyant escape of CO2. The method is particularly favorable when the aquifer dips, because CO2-saturated brine will tend to flow downslope. We perform two- and three-dimensional numerical simulations to study how far upslope the extraction well needs to be located to ensure a very long operation without CO2 ever breaking through. Several sets of simulations were carried out to evaluate the effect of slope, temperature, pressure and CO2 concentration, which is significantly reduced if flue gas (i.e., without capture) is mixed with the brine. We analyze energy requirements to find that the system requires high permeability to be viable, but its performance is improved by taking advantage of the thermal energy of the extracted brine.

Effects of thermal stresses on caprock integrity during CO2 storage

Subsurface fluid injection results in a pore pressure increase, which induces geomechanical stresses. Additionally, if there exists a difference between the ambient formation temperature and the temperature of injected fluid, thermal stresses can develop. Herein we study the effect of CO2 injection temperature on caprock integrity using coupled thermo-poromechanical multi-phase simulations. Calculations show that when CO2 is injected within several years at a temperature below the ambient value in the formation, the stresses above the horizontal injection well lead to tensile or shear failure of the caprock. We study the sensitivity of resulting stresses to the injection temperature, caprock density and initial in situ stresses. We also show that the caprock failure can lead to propagating fractures, which may serve as pathways for CO2 leakage. Based on the results of our simulations we estimate the rate of fracture propagation and study the effect of caprock permeability on this rate. Our results show that injection of CO2 at temperature close to the ambient value in the aquifer significantly reduces the risk of caprock fracturing and, therefore, of possible leakage.