Caprock Integrity Research Articles

Fracture Propagation Driven by Fluid Outflow from a Low-Permeability Aquifer

Deep saline aquifers are promising geological reservoirs for CO2 sequestration if they do not leak. The absence of leakage is provided by the caprock integrity. However, CO2 injection operations may change the geomechanical stresses and cause fracturing of the caprock. We present a model for the propagation of a fracture in the caprock driven by the outflow of fluid from a low-permeability aquifer. We show that to describe the fracture propagation, it is necessary to solve the pressure diffusion problem in the aquifer. We solve the problem numerically for the two-dimensional domain and show that, after a relatively short time, the solution is close to that of one-dimensional problem, which can be solved analytically. We use the relations derived in the hydraulic fracture literature to relate the the width of the fracture to its length and the flux into it, which allows us to obtain an analytical expression for the fracture length as a function of time. Using these results we predict the propagation of a hypothetical fracture at the In Salah CO2 injection site to be as fast as a typical hydraulic fracture. We also show that the hydrostatic and geostatic effects cause the increase of the driving force for the fracture propagation and, therefore, our solution serves as an estimate from below. Numerical estimates show that if a fracture appears, it is likely that it will become a pathway for CO2 leakage.

Predicting hydraulic tensile fracture spacing in strata-bound systems

A model is presented which predicts the spacing of tensile-fractures due to fluid pressure increase in a multilayered sedimentary sequence comprising different typical sedimentary deposits such as mudstones, siltstones and sandstones. During normal burial and tectonic conditions, strata will undergo both extensional forces and an increase in fluid pressures. This model addresses the effects of the diffuse fluid pressure increase, and is useful for engineered applications such as the injection of fluid into a reservoir that may cause an increase of fluid pressure beneath a caprock, and for sedimentary sequences during normal digenetic processes of burial and fault activation. Analytical and numerical elastic stress strain solutions are compared to provide a robust normalised standard relationship for predicting the spacing of fractures. Key parameters are the local minimum horizontal stress, variability of the tensile strengths of the layers of a sedimentary sequence and the thickness of the beds. Permeability and storage are also shown to affect the fracture spacing. The model predicts many of the field observations made regarding strata-bound fracture systems, and should also prove useful in consideration of the impact of raised reservoir fluid pressures on caprock integrity.

Design of Caprock Integrity in Thermal Stimulation of Shallow Oil-Sands Reservoirs

Summary Stakeholders in in-situ oil-sands development take caprock-integrity issues seriously. The industry is faced with the challenge of determining an optimal operating pressure in the reservoir where, in general, the pressure should stay significantly low to ensure the caprock integrity while being significantly high for enhanced oil production and economics. This paper presents a comprehensive work program on the subject for a shallow oil-sands play. Caprock integrity considers the induced stress and deformation in a caprock during the thermal stimulation of an oil-sands reservoir. A minifrac-test program is undertaken to define the original in-situ stress state. Laboratory tests are carried out to measure the deformation and strength properties. Simulations are run to calculate the induced stresses and evaluate them against the mechanical strength. This paper describes some important quality-control issues for these activities. For the minifrac tests, multiple cycles and use of flowback are promoted for enhanced efficiency and accuracy. Laboratory tests are recommended on whole cores in a drained condition at a slow strain rate. Numerical simulations should use site-specific and laboratory-measured material properties. On the basis of the limited sensitivity analyses, the thermal expansion coefficient of the reservoir and Young's modulus of the caprock are found to significantly affect the caprock deformation and/or induced stresses.

Evaluation of Induced Thermal Pressurization in Clearwater Shale Caprock in Electromagnetic Steam-Assisted Gravity-Drainage Projects

SummaryInductive methods, such as electromagnetic steam-assisted gravity drainage (EM-SAGD), have been identified as technically and economically feasible recovery methods for shallow oil-sands reservoirs with overburdens of more than 30 m (Koolman et al. 2008). However, in EM-SAGD projects, the caprock overlying oil-sands reservoirs is also electromagnetically heated along with the bitumen reservoir. Because permeability is low in Alberta thermal-project caprock formations (i.e., the Clearwater shale formation in the Athabasca deposit and the Colorado shale formation in the Cold Lake deposit), the pore pressure resulting from the thermal expansion of pore fluids may not be balanced with the fluid loss caused by flow and the fluid-volume changes resulting from pore dilation. In extreme cases, the water boils, and the pore pressure increases dramatically as a result of the phase change in the water, which causes profound effective-stress reduction. After this condition is established, pore pressure increases can lead to shear failure of the caprock, the creation of microcracks and hydraulic fractures, and subsequent caprock integrity failure. It is typically believed that low-permeability caprocks impede the transmission of pore pressure from the reservoir, making them more resistant to shear failure (Collins 2005, 2007). In cases of induced thermal pressurization, low-permeability caprocks are not always more resistant. In this study, analytical solutions are obtained for temperature and pore-pressure rises caused by the constant EM heating rate of the caprock. These analytical solutions show that pore-pressure increases from EM heating depend on the permeability and compressibility of the caprock formation. For stiff or low-compressibility media, thermal pressurization can cause fluid pressures to approach hydrostatic pressure, and shear strength to approach zero for low-cohesive-strength units of the caprock (units of the caprock with high silt and sand percentage) and sections of the caprock with pre-existing fractures with no cohesion.

Analysis of main controlling factors for hydrocarbon accumulation in central rift zones of the Hailar-Tamtsag Basin using a fault-caprock dual control mode

The Hailar-Tamtsag Basin is a typical rift basin where two sets of regional caprocks are developed, i.e., mudstone caprocks (containing a small amount of tuff) developed in strong rifting stage and fault-depression stage, respectively. The caprocks have a cumulative thickness of 50–120 m in general, and a single-layer thickness of 20–50 m, interbedded with sandstone about 1–2 m thick. The large set of mudstone is distributed continuously, as pure mudstone caprock. Forty-three mudstone and tuff samples were taken to perform displacement pressure test with our independently developed displacement pressure tester. Test result shows that the displacement pressure is 0.04–10.00 MPa, which is equivalent to 0.09–20.01 MPa after being corrected to the actual burial depth. As the burial depth increases, the displacement pressure rises gradually, and is 1–10 times greater than that of oil-bearing sandstone or conglomerate reservoir at the same burial depth. The difference between displacement pressure of mudstone caprock and sandstone or conglomerate reservoir increases greatly if the burial depth exceeds 1000 m. Because of the displacement pressure difference between caprock and reservoir, the maximum height of hydrocarbon column sealed by the caprock ranges from 300 m to 2000 m, much higher than the height of the trap closure at the same burial depth. No hydrocarbons will leak through such caprocks. Analysis of the reservoir GOI, homogeneous temperature, and crude maturity of both deep and shallow reservoirs in Well Wu-20 in the Wuerxun Depression shows that Damoguaihe II Member reservoir is a secondary reservoir developed during adjustment of early reservoir. It is mainly distributed in inverted structures. Faulting is one of the main factors breaking the integrity of caprocks. Three kinds of faults are often related to the migration of hydrocarbons across regional caprocks: the first type refers to the positive inverted faults breaking the early sealing conditions and making the hydrocarbons accumulated in the early period re-migration; the second type refers to the faults with shear mudstone smear structures which lose their continuity and open vertically when the fault throws exceed 5 times of the mudstone thickness; the third type refers to the normal faults developed in the structural inversion stage, which have a typical cataclastic structure and are easy to cause vertical migration of hydrocarbons. Hydrocarbon enriched horizons of the rift basins are co-controlled by “fault-caprock”. Specifically, 95% of the geological reserve is controlled by regional caprocks, and only 5% is controlled by open faults, secondary oil/gas reservoirs are developed over regional caprocks.

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.

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.

The special issue “Underground storage of CO2 and energy” in the framework of the 3rd Sino-German conference in May 2013

Greenhouse gas emissions, energy security and sustainability are three of the greatest contemporary global challenges to mankind today. The Sino-German Group of scientists have composed a special issue, which is a collection of diverse quality scientific works, that will try to elucidate the current developments in CO2 geologic sequestration research to reduce greenhouse emission including measures to monitor surface leakage, groundwater quality and the integrity of caprock, while ensuring a sufficient supply of clean energy.

Time-lapse shear wave splitting analysis to monitor caprock integrity at Delhi Field, Louisiana

Time-lapse shear wave splitting analysis to monitor caprock integrity at Delhi Field, Louisiana

Testing helium equilibrium between quartz and pore water as a method to determine pore water helium concentrations

The effectiveness of carbon capture and geologic storage depends on many factors, including and especially the permeability of the reservoir’s caprock. While caprock integrity is generally assumed if petroleum has been preserved, it is poorly constrained in reservoirs containing only saline waters, and CO2 leakage poses a potential risk to shallow aquifers. Naturally-occurring He accumulates in pore waters over time with the concentration being strongly dependent on the long term flux of fluid through the caprock. Furthermore, a small fraction of pore-water He diffuses into quartz and this may be used as a proxy for He concentrations in pore water, where dissolved gas samples are difficult to obtain, such as in deep sedimentary basins. In this paper He contained in quartz grains is measured and compared to previously measured pore water concentrations. Quartz was purified from core samples from the San Juan Basin, New Mexico and the Great Artesian Basin, South Australia. Quartz separates were heated at 290°C to release He from the quartz. The quartz from the San Juan Basin and high purity quartz from the Spruce Pine Intrusion, North Carolina was repeatedly impregnated at varying pressures using pure He, heated and analyzed to build He sorption isotherms. The isotherms appear linear but vary between samples, possibly due to fluid inclusions within the quartz grains as high purity quartz samples partition only 1.5% of He that partitions into San Juan Basin samples. Concentrations of He in the pore water were calculated using the He-accessible volume of the quartz and the air–water He solubility. The mean San Juan Basin He pore water concentration was 2×10–5cc STP He/g water, ∼400 times greater than atmospheric solubility. Great Artesian Basin samples contain a mean He concentration of 3×10–6cc STP He/g water or 65 times greater than atmospheric solubility. However, pore water He concentrations in both the San Juan and Great Artesian Basins differ by up to an order of magnitude compared to samples collected with an alternate method. The reason for the offset is attributable to either partial saturation of the pore volume or a lack of He equilibrium between quartz and pore water. Coating of clay or other mineral phases on quartz grains, which tends to reduce the effective diffusion coefficient, may cause the latter. This technique of assessing permeability is promising due to the abundance of existing core samples from numerous basins where carbon sequestration may ultimately occur.

Effective Caprock Determination for SAGD Projects

Summary In the oilsands of western Canada, caprock integrity has become a central issue in projects using steam-injection-recovery processes such as steam-assisted gravity drainage (SAGD). Caprocks contain steam and fluids within the reservoir; therefore, understanding the integrity of the caprock over the life of the operation is critical in order to ensure a safe and economically viable project. A multidisciplinary study was undertaken to evaluate geological facies as potential caprock for Ivanhoe Energy's Tamarack project. This examination of the historical performance of operating SAGD projects correlated the maximum vertical growth of the steam chamber with geology and the steam-injection operating pressure. The study found that SAGD steam chambers are being constrained by geological facies grading upward to poorer reservoir quality, rather than being constrained by shallower, regionally extensive, massive, low-permeability barriers. Geomechanical reservoir simulations of Ivanhoe Energy's proposed Tamarack SAGD project predict that the steam chamber will be constrained similarly as reservoir quality degrades upward. The simulations show the pressure and stress gradients in the formations above the steam chamber as a function of time and operating conditions, allowing for a more accurate assessment of steam containment and the risk for shear and/or tensile failure. The findings are significant because they confirm that the vertical growth of SAGD steam chambers has been halted, in effect, by facies consisting of interbedded sands and mudstones. These effective caprock facies have higher fracture pressures than the regionally extensive low-permeability barriers because these facies are found at greater depths. The higher fracture pressure justifies a higher maximum operating pressure, with its associated higher reservoir temperatures resulting in much lower bitumen viscosities. As a result, SAGD well productivity and project economics are greatly improved, particularly for shallow SAGD projects.

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.

Pore Scale Processes Associated with Subsurface CO2 Injection and Sequestration

The injection of CO2 into the Earth’s subsurface drives the fluid-rock system into “far-from- equilibrium” conditions, which means that the fluxes that return the system to equilibrium are nonlinearly related to the generalized driving forces (e.g., chemical affinities and gradients in the fluid pressures and chemical potentials). The nonlinear response results in emergent structures and self-organization (Prigogine 1968, 1980; Ortoleva 1994; Lasaga 1998; Jamtveit and Meakin 1999), of which the reactive infiltration instability is a well-known example in the Earth Sciences that is directly applicable to CO2 injection and caprock integrity (Ortoleva et al. 1987; Hoefner and Fogler 1988; Steefel and Lasaga 1994; Steefel and Maher 2009). Flow, solute transport, colloid transport, mineral dissolution and mineral precipitation combine within the mechanical framework of the porous medium to generate precipitate structures in individual pores correlated over many thousands to millions of pores, and immiscible fluid structures with fractal geometry over scales from millimeters to kilometers (Feder 1988). The focus in this chapter is on processes, emergent and otherwise, taking place at the pore scale, defined here as the scale where individual grains and fluid interfaces can be resolved. The chief focus of research in recent years has been to improve the understanding of the nonlinear dynamics specifically associated with biogeochemical and microbially induced processes coupled to physical processes such as flow and diffusion at the pore scale. When coupled, whether in field-scale applications, bench-scale experiments, or in models, emergent behavior may result, including changes in permeability, diffusivity, and reactivity. The pore scale is an important scale to analyze these emergent behaviors given that it provides the architecture within which the smaller scale (nano and molecular scale) processes occur. For the individual processes to interact, transport is typically necessary and the resulting behavior …

Prediction of residual oil saturation and cap-rock integrity from time-lapse, multicomponent seismic data, Delhi Field, Louisiana

Time-lapse, multicomponent seismic data acquired during the CO2 flood at Delhi Field, Louisiana are used to identify zones containing high residual bulk oil volume and to target the location of new injection wells in the field. The data are used to monitor the reservoir and to see if the predicted zones of high residual oil are contacted by the enhanced oil recovery (EOR) process. Because the reservoir is shallow and injection pressures are relatively high, the cap rock is monitored. Stresses associated with injection induce observable shear-wave splitting anomalies in the cap rock. Stresses transmitted into the shale-confining layer by the injection process are not believed indicative of rupturing and CO2 leakage. The ability to monitor geomechanical changes through shear-wave splitting is an important new use of multicomponent seismic data.

Experimental Investigations of Caprock Integrity in CO2 Sequestration

The geochemical reactivity of shale caprock during post-injection CO2 diffusive transfer should be included in the reservoir characterization of CO2 sequestration sites as slow reactive transport processes can either improve or degrade seal integrity over the long term. Simulation results reported by various researchers suggested that influx-induced mineral dissolution/precipitation reactions within shale caprocks can continuously close micro-fracture networks, while pressure and effective-stress transformation first rapidly expand then progressively constrict them. This experimental work applied specific analytical techniques in investigating changes in mineralogical and microstructural properties of crushed shale rocks after exposure (by flooding) to CO2-brine for a time frame ranging between 30 days to 92 days at elevated pressure and fractional flow rate. The initial mineralogical composition in the samples showed bulk clay, quartz and feldspar as the major components of the formation. Initial capillary entry parameters for the shale were estimated from digitally acquired injection pressure profile. Flooding of the shale samples with CO2-brine was followed by geochemical characterization of the effluent fluid and bulk shale rock through pH and XRD measurements. Nano-scale measurement of changes in internal specific surface area and cumulative pore size distribution (using the BET Technique) revealed that changes in the shale caprock due to geochemical interaction with aqueous CO2 can affect petrophysical properties. The naturally low permeability in shale may be altered by changes in specific surface area as the effective permeability of any porous medium is largely a function of its total pore geometry/volume, and particularly the pore throat-diameter. The geochemical reactivity of shale caprocks through acidic fluid transport in interconnected pore networks gave insight into the impact of diffusion and reaction rate on shale caprock integrity in CO2 sequestration.

Study on Geomechanical Stability of the Aquifer -caprock System During CO2 Sequestration by Coupled Hydromechanical Modelling

Carbon dioxide (CO2) sequestration in deep aquifers is one of the options for reducing the emission of greenhouse gases to the atmosphere. It is efficient to inject super critical CO2 into an aquifer if the geomechanical stability of the aquifer -caprock system can be maintained during the injection. An axisymmetric horizontal aquifer -caprock system is modeled including hydromechanical coupling in order to study influence of various factors - such as injection rate, permeability and stiffness of the caprock and aquifer - on the stability and especially the integrity of the caprock. Here the local safety factor is considered as an index of caprock integrity. It is shown that the effective stress state of the caprock close to the injection well could become critical for shear failure quite early in the injection. A buildup of gas pressure in the aquifer causes caprock deformation, inducing an increase in deviatoric stress within the caprock. Larger injection rates and lower aquifer permeability amplify such phenomena, increasing the risk of losing caprock integrity. Increased aquifer stiffness, in contrast, restricts the caprock deformation, and lowers the risk.

Acid Gases in CO2-rich Subsurface Geologic Environments

The analysis of species behavior involving dilute fluid environments has been crucial for the advance of modern solvation thermodynamics through molecular-based formalisms to guide the development of macroscopic regression tools in the description of fluid behavior and correlation of experimental data (Chialvo 2013). Dilute fluid environments involving geologic formations are of great theoretical and practical relevance regardless of the thermodynamic state conditions. The most challenging systems are those involving highly compressible and reactive confined environments, i.e., where small perturbations of pressure and/or temperature can trigger considerable density changes. This in turn can alter significantly the species solvation, their preferential solvation, and consequently, their reactivity with one another and with the surrounding mineral surfaces whose outcome is the modification of the substrate porosity and permeability, and ultimately, the integrity of the mineral substrates. Considering that changes in porosity and permeability resulting from dissolution and precipitation phenomena in confined environments are at the core of the aqueous CO2-mineral interactions, and that caprock integrity (e.g., sealing capacity) depends on these key parameters, it is imperative to gain fundamental understanding of the mineral-fluid interfacial phenomena and fluid-fluid equilibria under mineral confinement at subsurface conditions. In order to understand the potential effects of acid gases as contaminants of supercritical CO2 streams, in the next section we will discuss the thermodynamic behavior of CO2 fluid systems by addressing two crucial issues in the context of carbon capture, utilization and sequestration (CCUS) technologies: (i) Why should we consider (acid gas) CO2 impurities? and (ii) Why are CO2 fluid - mineral interactions of paramount relevance? ### Background on flue gas sources, composition, and CO2 - acid gases co-injection The control of anthropogenic greenhouse gases emissions in the atmosphere by means of their capture and sequestration in deep geological reservoirs has emerged as a potential technology for the middle- to long-term mitigation of the greenhouse effect …

Potential Global Implications of Gas Production from Shales and Coal for Geological CO2 Storage

Production of natural gas from shale formations and coal deposits is increasing, and new potential productive horizons are being identified. Producers are using horizontal drilling and hydraulic fracturing technologies to economically produce oil and gas from shales and coal seams. These technologies open up the possibility of using shales and coals as actual storage media for carbon dioxide (CO2) by increasing permeability and injectivity; though some worry that the same technology may compromise the integrity of shale cap rocks in some basins.This paper builds upon previous work to assess the global potential for geological storage of CO2 in shale and coal formations. This includes assessment and characterization of: (1) the global status of hydrocarbon production from shales and coal seams; (2) the potential theoretical capacities for CO2 storage in shales and coals; and (3) containment issues arising from shale fracturing, both for shales as a storage medium, and in terms of cap rock integrity for underlying storage units, particularly deep saline formations.Technical recovery potential for methane from the world's coal seams is estimated to be 79 trillion cubic meters (Tcm) globally, which could facilitate the potential storage of nearly 488 billion metric tons, or Gigatonnes (Gt), of CO2 in unmineable coal seams. In gas shales, an estimated 188Tcm of shale gas resources are potentially technically recoverable globally, and could facilitate the potential storage of 740 Gt of CO2 in gas shales.Concerns about the potential adverse impacts of the use of saline aquifers underlying gas shale formations for CO2 storage overlook the critical third dimension – depth. Sedimentary basins consist of thousands of meters of multiple layers of shale, sandstones, limestones, etc. (that may also be “tight” or largely impermeable). If one shale formation layer directly above a storage zone is fractured; additional layers of impermeable rock overlying the fractured area could block upward migration of the CO2. Moreover, in many cases, even the targeted shale will not be fractured throughout its entire thickness, which could be hundreds of meters. With sensible safeguards, CO2 storage reservoirs can, in most areas, coexist with conventional and unconventional oil and gas operations, including shale gas production and hydraulic fracturing.

ULTimateCO2: A FP7 European Project Dedicated to the Understanding of the Long Term Fate of Geologically Stored CO2

ULTimateCO2 will assess the long-term CO2 storage behaviour in terms of efficiency and security. The project is dedicated to studying the main physical processes needed to develop a better, quantitative understanding of the long- term geological storage of CO2, namely: (i) reservoir trapping, (ii) sealing integrity of caprock, and (iii) well leakage. Close collaboration with the NER300 candidates and EEPR demonstration sites will underpin all investigation with relevant supply of data industrial context. ULTimateCO2 will define a set of recommendations that will enable both regulators and operators to demonstrate that site specific long-term site performance will lead to permanent and safe CO2 containment.

Clay Hydration/dehydration in Dry to Water-saturated Supercritical CO2: Implications for Caprock Integrity

Injection of supercritical CO2 (scCO2) for the geologic storage of carbon dioxide will displace formation water, and the pore space adjacent to overlying caprocks could eventually be dominated by dry to water- saturated scCO2. Wet scCO2 is highly reactive and capable of carbonating and hydrating certain minerals, whereas anhydrous scCO2 can dehydrate water-containing minerals. Because these geochemical processes affect solid volume and thus porosity and permeability, they have the potential to affect the long-term integrity of the caprock seal. In this study, we investigate the swelling and shrinkage of an expandable clay found in caprock formations, montmorillonite (Ca-STx-1), when exposed to variable water-content scCO2 at 50°C and 90bar using a combination of in situ probes, including X-ray diffraction (XRD), in situ magic angle spinning nuclear magnetic resonance spectroscopy (MAS NMR), and in situ attenuated total reflection infrared spectroscopy (ATR-IR). We show that the extent of montmorillonite clay swelling/shrinkage is dependent not only on water hydration/dehydration, but also on CO2 intercalation reactions. Our results also suggest a competition between water and CO2 for interlayer residency where increasing concentrations of intercalated water lead to decreasing concentrations of intercalated CO2. Overall, this paper demonstrates the types of measurements required to develop fundamental knowledge that will enhance modeling efforts and reduce risks associated with subsurface storage of CO2.