CO2 Sequestration Operations Research Articles

Coupled geomechanical analysis of irreversible compaction impact on CO2 storage in a depleted reservoir

The utilization of depleted gas reservoirs for carbon storage offers substantial advantages. However, it raises concerns related to the geomechanical effects of historic gas extraction on the CO2 sequestration operation. In this study, a coupled thermo-hydro-mechanical investigation is conducted on a multi-layered sedimentary system that includes sealed bounding faults. Our simulations exhibit various levels of reservoir compaction during gas extraction under different pre-consolidation conditions of the sediments, highlighting the pivotal role of reservoir compaction in geomechanical analysis. The results demonstrate the occurrence of strain-hardening compaction behavior in the reservoir during post-yield depletion. This compaction is accompanied by a significant reduction in porosity and permeability, as well as irreversible surface subsidence. Hysteresis in the stress state is induced by the aforementioned irreversible reservoir compaction through two primary mechanisms: poro-elastoplastic stressing and differential compaction on each side of the sealing fault. These mechanisms alter the magnitude and orientation of stress inside and outside the depleted reservoir. Moreover, caprock compaction is impeded and delayed by the irreversible reservoir compaction owing to poro-elastoplastic stressing. This implies that conventional methods relying on the poro-elasticity theory alone may overestimate pressure required to fracture the caprock by approximately 2 MPa. When considering the combined effect of poro-elastoplastic stressing and differential compaction, neglecting irreversible reservoir compaction may lead to underestimation of the critical pressure for inducing fault slip by up to 4.9 MPa. Additionally, regardless of whether plastic void compaction is considered, we recommend increased attention be focused on the sub-vertical faults to mitigate the risk of significant slip that potentially could also lead to upward CO2 leakage. In scenarios where a slip event occurs in a fault during reservoir depletion, the results show that a subsequent CO2 injection operation tends to stabilize the faults. Nevertheless, it is crucial to consider that fault stability could deteriorate rapidly over time, potentially leading to a second slip event during carbon sequestration.

Mechanisms for Microseismicity Occurrence Due to CO2 Injection at Decatur, Illinois: A Coupled Multiphase Flow and Geomechanics Perspective

ABSTRACT We numerically investigate the mechanisms that resulted in induced seismicity occurrence associated with CO2 injection at the Illinois Basin–Decatur Project (IBDP). We build a geologically consistent model that honors key stratigraphic horizons and 3D fault surfaces interpreted using surface seismic data and microseismicity locations. We populate our model with reservoir and geomechanical properties estimated using well-log and core data. We then performed coupled multiphase flow and geomechanics modeling to investigate the impact of CO2 injection on fault stability using the Coulomb failure criteria. We calibrate our flow model using measured reservoir pressure during the CO2 injection phase. Our model results show that pore-pressure diffusion along faults connecting the injection interval to the basement is essential to explain the destabilization of the regions where microseismicity occurred, and that poroelastic stresses alone would result in stabilization of those regions. Slip tendency analysis indicates that, due to their orientations with respect to the maximum horizontal stress direction, the faults where the microseismicity occurred were very close to failure prior to injection. These model results highlight the importance of accurate subsurface fault characterization for CO2 sequestration operations.

CO2 leak detection threshold using vertical seismic profiles

At the Containment and Monitoring Institute Field Research Station in Alberta, Canada, CO2 is being injected into a saline aquifer at 300 m depth to simulate a shallow leak from a deep carbon sequestration operation. The injection interval is a 7 m thick sandstone with a porosity of 11%. The gas-phase CO2 plume was detected with time-lapse vertical seismic profiles (VSP) after 32 tonnes of CO2 had been injected. The VSP surveys had high repeatability with permanent borehole geophones and carefully repeated source locations. A data processing workflow was developed to produce directly comparable baseline and monitor amplitudes while preserving subtle amplitude changes caused by partial CO2 saturation. Seasonal variations in the physical properties of the near-surface glacial tills introduced spectral differences between baseline and monitor datasets that were successfully mitigated by deterministic deconvolution and selected band-pass filters. The 32 t detection threshold represents a lower limit of CO2 detectability with borehole geophones in this geological setting. These results provide a rare field data example of CO2 monitoring at shallow to intermediate depths and demonstrate that VSP surveys are capable of identifying loss of containment in industrial-scale CO2 sequestration operations.

Life Cycle Assessment of Hydrogen Production from Coal Gasification as an Alternative Transport Fuel

The gasification of Polish coal to produce hydrogen could help to make the country independent of oil and gas imports and assist in the rational energy transition from gray to green hydrogen. When taking strategic economic or legislative decisions, one should be guided not only by the level of CO2 emissions from the production process, but also by other environmental impact factors obtained from comprehensive environmental analyses. This paper presents an analysis of the life cycle of hydrogen by coal gasification and its application in a vehicle powered by FCEV cells. All the main stages of hydrogen fuel production by Shell technology, as well as hydrogen compression and transport to the distribution point, are included in the analyses. In total, two fuel production scenarios were considered: with and without sequestration of the carbon dioxide captured in the process. Life cycle analysis was performed according to the procedures and assumptions proposed in the FC-Hy Guide, Guidance Document for performing LCAs on Fuel Cells and H₂ Technologies by the CML baseline method. By applying the CO2 sequestration operation, the GHG emissions rate for the assumed functional unit can be reduced by approximately 44% from 34.8 kg CO2-eq to 19.5 kg CO2-eq, but this involves a concomitant increase in the acidification rate from 3.64·10−2 kg SO2-eq to 3.78·10−2 kg SO2-eq, in the eutrophication index from 5.18·10−2 kg PO3−4-eq to 5.57·10−2 kg PO3−4-eq and in the abiotic depletion index from 405 MJ to 414 MJ and from 1.54·10−5 kg Sbeq to 1.61·10−5 kg Sbeq.

Evaluation of Geo-Mechanical-Chemical Impacts of Co2 Injection to Depleted Oil Reservoirs

This paper presents a more holistic approach in evaluating the impacts of CO2 injection in CO2 sequestration operations in a depleted Morrow B sandstone of the Farnsworth Unit, Ochiltree County, Texas. The complex interactions between CO2 and the formation fluids (oil and brine) and the acidized brine interactions with formation rock when coupled with mechanical processes present an integrated and realistic effect of CO2 injection in the underground environment. In light of this, different coupled numerical simulation models were developed to investigate the various CO2 trapping mechanisms and the long-term fate of CO2 in a depleted Morrow B sandstone. The models include hydrodynamical model, coupled hydrodynamical-mechanical model, coupled hydrodynamical-chemical model, and coupled hydrodynamical-chemical-mechanical model. A WAG operation was carried out for 20 years after the history period and followed by a post-injection period of 1000 years to monitor and evaluate the effect of the injected CO2 on the underground environment. This work shows that geomechanics impacted the petrophysical properties of the reservoir and had significant impact on the injectivity of CO2. The chemical reactions had very little impact on the petrophysical properties of the reservoir. The different simulation scenarios resulted in variable amounts of storage within the partially depleted oil reservoir.

A metric for evaluating conformance robustness during geologic CO2 sequestration operations

A metric for quantifying the robustness of a designation of conformance of a geologic CO2 sequestration (GCS) project during its operational phase is developed and demonstrated. Conformance in this context is a measure of the degree to which the sequestration system is understood and can be accurately modeled along with the degree to which the storage system is performing as designed. The robustness of conformance quantifies the degree to which parameter values can deviate from their current nominal estimates and still produce model forecasts that meet the performance criteria for the GCS operation. We develop and demonstrate the approach on a simplified scenario to illustrate the concept using a single uncertain parameter (homogeneous reservoir permeability) and a single performance criterion (critical pressure at a monitoring well in the reservoir; i.e., one that may displace brine from the reservoir to an overlying drinking water aquifer for example). Increased confidence in conformance assessment as more monitoring data are obtained is incorporated through the standard error of the coefficient (reservoir permeability in the case presented here), which we designate as the concordance metric. As more monitoring data become available during the course of the GCS operation, the standard error of the coefficient decreases (in general), thereby leading to increased conformance robustness as a larger deviation from nominal is required to fail to meet performance criteria. Increasing conformance robustness over time builds confidence that a GCS project will continue to meet performance criteria during the life-span of the project, thereby supporting designations of conformance. A lack of conformance robustness provides a critical warning that the performance criteria of the GCS operation are not robust against probabilistic and non-probabilistic uncertainty in model conceptualization and/or model parameters.

Prediction of CO2 leakage risk for wells in carbon sequestration fields with an optimal artificial neural network

Carbon Capture and Storage (CCS) is a key climate mitigation technology. Leakage of the injected CO2 is one of the major environmental concerns. The potential for CO2 leakage from wells is one of the critical risks identified in geological CO2 sequestration. The objective of this study is to develop a computerized statistical model with the neural network algorithm for predicting the probability of long-term leak of wells in CO2 sequestration operations. Well design and operation data for over 500 CO2 exposed wells were generated from the West Hastings oil field and Oyster Bayou oil field in southern Texas, USA. The well integrity conditions were assessed by analyzing the well attribute data (well type, well age, CO2 exposed period, well construction details and materials), well operation histories and regulatory changes. Leakage-safe Probability Index (LPI) was assigned to individual wells. A computerized statistical model with network algorithm was developed based on data processing and grouping. Comprehensive training and testing of the model were carried out to ensure that the model was accurate and efficient enough for predicting the probability of long-leak of wells in CO2 sequestration operations. The accuracy of the trained neural network for well leakage prediction was also verified by the field operation in the Cranfield Field, Mississippi, USA. The developed neural network model can improve the efficiency of the storage operations by predicting the risk of CO2 leakage in the current exposed wells. In addition, it can also contribute in developing best practices standards by proposing recommendations for well construction in future wells.

Effects of the distribution and evolution of the coefficient of friction along a fault on the assessment of the seismic activity associated with a hypothetical industrial-scale geologic CO2 sequestration operation

Carbon capture and storage (CCS) in geological formations is considered as a promising option that could limit CO2 emissions from human activities into the atmosphere. However, there is a risk that pressure buildup inside the storage formation can induce slip along preexisting faults and create seismic event felt by the population. To prevent this to happen a geomechanical fault stability analysis should be performed, considering uncertainties of input parameters. In this paper, we investigate how the distribution of the coefficient of friction and the applied frictional law could influence the assessment of fault stability and the characteristics of potential injection-induced seismic events. Our modelling study is based on a hypothetical industrial-scale carbon sequestration project located in the Southern San Joaquin Basin in California, USA, where the stability on a major (25km long) fault that bounds the sequestration site is assessed during 50 years of CO2 injection. We conduct nine simulations in which the distributions of the coefficients of static and dynamic friction are changed to simulate a hardening and softening phase before and during rupture. Our main findings are: (i) variations in friction along the fault have an important effect on the predicted seismic activity, with maximum magnitude ranging from 1.88 to 5.88 and number of seismic events ranging from 338 to 3272; (ii) the extreme values of the coefficient of friction (lowest and highest) present along the rupture area control how much stress is accumulated before rupture; and (iii) an argillaceous caprock can prevent the development of large magnitude seismic events but favor the occurrence of a large number of smaller events.

Desalination of hypersaline brines via Joule-heating: Experimental investigations and comparison of results to existing models

Thermodynamic data of multicomponent brines are needed to properly treat brines from oil/gas and CO2 sequestration operations. Joule-heating treatment of hypersaline brine is a unique methodology that allows for direct heating of brines without the need of external heating, potentially simplifying operation and reducing process footprint. The thermodynamic properties of multicomponent hypersaline brine (>3.5wt%) are unknown and limited to estimations based on single component brine data. Experimental data for multicomponent brines at elevated temperatures and pressures do not exist due to operating conditions above the pseudocritical point of pure water. This study combines experimental results for multicomponent brines using a Joule- heated desalinator at pressures of 230 to 280bar and temperatures of 387 to 406°C with thermodynamic models previously created for single component NaCl brines to identify the deviations resulting from the additional species. In addition, a comparison between an Aspen Plus® v9 simulation using the ELECTNRTL model with experimental results is provided.

Prediction of the maximum allowable bottom hole pressure in CO2 injection wells

Mechanical failure of well cement sheath can result in loss of zonal isolation, which is the cause of many problems, such as sustainable casing pressure, crossflows between formation zones, and leakage of fluid to surface. Pressure- and temperature-induced stresses in the cement sheath have been numerically analyzed by a number of previous investigators with sophisticated computer models. However, these investigations do not provide a practical method for predicting the maximum permissible pressure limited by the mechanical failure of cement sheath.An analytical model was derived in this work to predict the Maximum Permissible Pressure (MaxPP) in fluid injection and well stimulation. Results given by the model were verified with data from a CO2 sequestration operation. Case studies with the model suggest that if the cement placement efficiency in the annulus is 100% as detected by CBL, formation in-situ stress should be utilized to make a conservative prediction of the MaxPP. If the cement placement efficiency in the annulus is less than 100% detected by CBL, the outer radius of the cement sheath should be considered and formation pore pressure in the cap rock should be employed to make a conservative prediction of the MaxPP. Improving cement strength is not an effective means of increasing MaxPP. The MaxPP should be enhanced by maximizing the outer radius of the cement sheath through improving the cement placement efficiency. The Maximum Permissible Net Pressure is lower than the burst-pressure rating of casing, suggesting that cement sheath failure will occur before casing failure occurs in the burst condition. Therefore burst design should be carried out for cement sheath, not production casing. This paper provides engineers a practical guideline to design and apply fluid injection pressure in well stimulation and operations.

Effects of in situ stress measurement uncertainties on assessment of predicted seismic activity and risk associated with a hypothetical industrial-scale geologic CO2 sequestration operation

Carbon capture and storage (CCS) in geologic formations has been recognized as a promising option for reducing carbon dioxide (CO2) emissions from large stationary sources. However, the pressure buildup inside the storage formation can potentially induce slip along preexisting faults, which could lead to felt seismic ground motion and also provide pathways for brine/CO2 leakage into shallow drinking water aquifers. To assess the geomechanical stability of faults, it is of crucial importance to know the in situ state of stress. In situ stress measurements can provide some information on the stresses acting on faults but with considerable uncertainties. In this paper, we investigate how such uncertainties, as defined by the variation of stress measurements obtained within the study area, could influence the assessment of the geomechanical stability of faults and the characteristics of potential injection-induced seismic events. Our modeling study is based on a hypothetical industrial-scale carbon sequestration project assumed to be located in the Southern San Joaquin Basin in California, USA. We assess the stability on the major (25 km long) fault that bounds the sequestration site and is subjected to significant reservoir pressure changes as a result of 50 years of CO2 injection. We present a series of geomechanical simulations in which the resolved stresses on the fault were varied over ranges of values corresponding to various stress measurements performed around the study area. The simulation results are analyzed by a statistical approach. Our main results are that the variations in resolved stresses as defined by the range of stress measurements had a negligible effect on the prediction of the seismic risk (maximum magnitude), but an important effect on the timing, the seismicity rate (number of seismic events) and the location of seismic activity.

Treatment of produced water from an oilfield and selected coal mines in the Illinois Basin

If large-scale CO2 sequestration operations are implemented in oilfields or coal mines, large volumes of water (i.e., produced water) could potentially be generated that would need to be properly managed. In this work, produced water samples with total dissolved solids (TDS) values of 18,000–102,000mg/L (ppm) were collected from an oilfield, a coal-bed methane field, and a coal mine in the Illinois Basin of the United States and were treated by selected conventional pretreatment processes followed by a reverse osmosis desalination process. Pretreatment processes included coagulation by lime, ferric chloride, or aluminum sulfate; filtration by sand, walnut shells, anthracite coal, or microfiltration; and adsorption by organoclay, activated carbon, or ion-exchange resins. Selected pretreatment processes were sufficient for removing most of the contaminants, but the high sodium background of the high-TDS produced water (102,000ppm) limited the effectiveness of the ion-exchange pretreatment in removing scale-forming species. Reverse osmosis was a practical process for desalination of pretreated produced water samples tested (by reducing the TDS more than 96%) except for the high-TDS produced water. Reported bench-scale produced water treatment data might be beneficial for the design and operation of pilot-scale plants for treating produced waters with similar properties.

Impact of wettability alteration on 3D nonwetting phase trapping and transport

We investigate capillary trapping and fluid migration via x-ray computed microtomography (x-ray CMT) of nonwetting phase (air) and wetting phase (brine) in Bentheimer sandstone cores which have been treated to exhibit different degrees of uniform wettability. x-Ray CMT scans were acquired at multiple steps during drainage and imbibition processes, as well as at the endpoints; allowing for assessment of the impact of wettability on nonwetting phase saturation and cluster size distribution, connectivity, topology and efficiency of trapping. Compared with untreated (water-wet) Bentheimer sandstone, cores treated with tetramethoxylsilane (TMS) were rendered weakly water-wet, and cores treated with octadecyltrichlorosilane (OTS) demonstrate intermediate-wet characteristics. As apparent contact angle increases, drainage flow patterns deviate from those derived for water-wet systems, total residual trapping and trapping efficiency decrease, and buoyancy plays a larger role during nonwetting phase mobilization; this has significant implications for CO2 migration and trapping during CO2 sequestration operations.

Bridging aero-fracture evolution with the characteristics of the acoustic emissions in a porous medium

The characterization and understanding of rock deformation processes due to fluid flow is a challenging problem with numerous applications. The signature of this problem can be found in Earth Science and Physics, notably with applications in natural hazard understanding, mitigation or forecast (e.g. earthquakes, landslides with hydrological control, volcanic eruptions), or in industrial applications such as hydraulic-fracturing, steam-assisted gravity drainage, CO₂ sequestration operations or soil remediation. Here we investigate the link between the visual deformation and the mechanical wave signals generated due to fluid injection into porous media. In a rectangular Hele-Shaw Cell, side air injection causes burst movement and compaction of grains along with channeling (creation of high permeability channels empty of grains). During the initial compaction and emergence of the main channel, the hydraulic fracturing in the medium generates a large non-impulsive low frequency signal in the frequency range 100 Hz - 10 kHz. When the channel network is established, the relaxation of the surrounding medium causes impulsive aftershock-like events, with high frequency (above 10 kHz) acoustic emissions, the rate of which follows an Omori Law. These signals and observations are comparable to seismicity induced by fluid injection. Compared to the data obtained during hydraulic fracturing operations, low frequency seismicity with evolving spectral characteristics have also been observed. An Omori-like decay of microearthquake rates is also often observed after injection shut-in, with a similar exponent p≃0.5 as observed here, where the decay rate of aftershock follows a scaling law dN/dt ∝(t-t₀ )-p . The physical basis for this modified Omori law is explained by pore pressure diffusion affecting the stress relaxation.

Prediction of supercritical CO2/brine relative permeability in sedimentary basins during carbon dioxide sequestration

AbstractThis study aims to accurately determine supercritical CO2/brine relative permeability, using a hybrid Genetic Algorithm‐Radial Basis Function (GA‐RBF) neural network. CO2 sequestration, along with some enhanced oil recovery (EOR) processes, demands an exact knowledge of relative permeability in order to ensure the viability of the operation. Previous studies have shown that errors in CO2/brine relative permeability data might result in a four‐fold error in injectivity estimation. This, as well as several recent studies regarding the relative permeability of CO2/brine systems, has indicated the importance of this parameter. The developed GA‐RBF model was determined to be in excellent accordance with experimental data, yielding average absolute relative deviations (AARD) of 4.66% and 2.11% for CO2 and brine relative permeability, respectively. In addition, comprehensive comparisons between classic models and the proposed GA‐RBF model have been carried out. Based on these comparisons, it may be concluded that the proposed model is superior to the classic method (simple correlation) in terms of its accuracy in determining the viability of CO2 sequestration operations. © 2015 Society of Chemical Industry and John Wiley & Sons, Ltd

Influence of microporosity distribution on the mechanical behavior of oolithic carbonate rocks

The mechanical behavior of oolithic carbonate rocks was investigated for selected rocks with two different microstructural attributes: uniform (UP) and rimmed (RP) distribution of microporosity within ooids. These oolithic carbonate rocks are from the Oolithe Blanche formation, a deep saline aquifer in the Paris Basin, and a possible target for CO2 sequestration and geothermal production. Samples of similar physical properties (porosity, grain diameter, cement content) but different microporosity textures were deformed under triaxial configuration, in water saturated conditions, at 28 MPa of confining pressure, 5 MPa of pore pressure and at a temperature of 55 °C. During the experiments, acoustic velocities were monitored, and permeability was measured. The results show that the mechanical behavior of these microporous carbonates are strongly controlled by the microporosity distribution within the grains, at the origin of variations in elastic properties, mechanical strength and failure mode. The lower velocities measured in UP samples indicate a larger compliance of the whole structure. The mechanical response indicates that UP samples are characterized by a ductile behavior whereas RP samples display a brittle behavior. Using a conceptual model for the failure envelope of both rocks, our observations can be accounted for if one considers a significant variation of the critical pressure P∗, with UP samples having a lower P∗ than RP samples. The permeability evolution under stress was interpreted using a revised Kozeny–Carman equation, showing that fluid flow is strongly affected by the tortuosity of the pore space, which is controlled by the microporosity distribution within the ooids. This study brings new insight into the parameters controlling the physical and mechanical response of oolithic carbonates, and the possible impact on production of geothermal energy at depth or storativity for CO2 sequestration operations.

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.

Development of Improved caprock Integrity Analysis and Risk Assessment Techniques

Abstract GeoMechanics Technologies has completed a geomechanical caprock integrity analysis and risk assessment study funded through the US Department of Energy. The project included: a detailed review of historical caprock integrity problems experienced in the natural gas storage industry; advanced coupled transport flow modelling and geomechanical simulation of three large-scale potential geologic sequestration sites to estimate geomechanical effects from large-scale CO2 injection; and development of a quantitative risk and decision analysis tool to assess caprock integrity risks. Historical data from gas storage operations and CO2 sequestration projects suggest that leakage and containment incident risks are on the order of 10-1 to 10-2, which is higher risk than some previous studies have suggested for CO2. Geomechanical analysis, as described herein, can be applied to quantify risks and to provide operating guidelines to reduce risks. The risk assessment tool developed for this project has been applied to five areas: The Wilmington Graben offshore Southern California, Kevin Dome in Montana, the Louden Field in Illinois, the Sleipner CO2 sequestration operation in the North Sea, and the In Salah CO2 sequestration operation in North Africa. Of these five, the Wilmington Graben setting represent the highest relative risk while the Kevin Dome setting represents the lowest relative risk.

A new theoretical approach to model sorption-induced coal shrinkage or swelling

The shrinkage or swelling of coal as a result of gas desorption or adsorption is a well-accepted phenomenon. Its impact on permeability changes has also been recognized for two decades. Its importance has increased significantly because of the potential of coals that are not likely to be mined and depleted or nearly depleted coalbed methane reservoirs to serve as CO2 repositories. This article proposes a new theoretical technique to model the volumetric changes in the coal matrix during gas desorption or adsorption using the elastic properties, sorption parameters, and physical properties of coal. The proposed model is based on the theory of changes in surface energy as a result of sorption. The results show that the proposed model is in excellent agreement with the laboratory volumetric strain data presented in the literature during the last 50 yr. Furthermore, the proposed model can be extended to describe mixed-gas sorption behavior, which can be applied to enhanced coalbed methane and CO2 sequestration operations.

Coupled multiphase flow and geomechanics model for analysis of joint reactivation during CO2 sequestration operations

The initial and primary trapping mechanism for long term subsurface sequestration of CO2 is structural trapping beneath a low permeability caprock layer. Maintaining caprock integrity during injection operations is paramount to successful sequestration. Evaluation of jointed/fractured caprock systems is of particular concern to CO2 sequestration because creation of fractures or reactivation of joints can lead to enhanced pathways for leakage.In this work, a joint model is introduced to describe joint reactivation during injection of CO2. The model assumes equally spaced anisotropic joint sets with non-linear normal stiffness and linear shear stiffness. Normal displacement of the joints is mapped into a dynamically evolving effective anisotropic permeability tensor, assuming a cubic law for fracture permeability as a function of joint aperture. A model problem is presented to demonstrate features of the joint model and how it affects the coupled geomechanics and flow during injection of CO2 into deep saline aquifers. The model is used to demonstrate injection reservoir properties and injection rates that have potential for inducing leakage through the caprock due to overpressures associated with CO2 injection.In situations where pore pressure approaches or exceeds lithostatic pressure under a constant-rate, 30 year injection, the model indicates between 16 and 20% of injected CO2 could leak past the primary caprock after 50 years. The model also indicates a concomitant overpressure reduction that could signal caprock leakage during the injection.