Geological sequestration of carbon dioxide in deep saline aquifers: coupled flow-mechanical considerations

Study of reservoir rock and caprock integrity in geo-sequestration of carbon dioxide

The principal mechanisms for the geologic sequestration of carbon dioxide in deep saline aquifers include geological structural trapping, hydrological entrapment of nonwetting fluids, aqueous phase dissolution and ionization, and geochemical sorption and mineralization. In sedimentary saline aquifers the dominant mechanisms are structural and dissolution trapping, with moderate to weak contributions from hydrological and geochemical trapping; where, hydrological trapping occurs during the imbibition of aqueous solution into pore spaces occupied by gaseous carbon dioxide, and geochemical trapping is controlled by generally slow reaction kinetics. In addition to being globally abundant and vast, deep basaltic lava aquifers offer mineralization kinetics that make geochemical trapping a dominate mechanism for trapping carbon dioxide in these formations. For several decades the United States Department of Energy has been investigating Columbia River basalt in the Pacific Northwest as part of its environmental programs and options for natural gas storage. Recently this nonpotable and extensively characterized basalt aquifer is being reconsidered as a potential reservoir for geologic sequestration of carbon dioxide. The reservoir has an estimated storage capacity of 100 giga tonnes of carbon dioxide and comprises layered basalt flows with sublayering that generally alternates between low permeability massive and high permeability breccia. Chemical analysis of the formation shows 10 wt% Fe, primarily in the +2 valence. The mineralization reaction that makes basalt aquifers attractive for carbon dioxide sequestration is that of calcium, magnesium, and iron silicates reacting with dissolved carbon dioxide, producing carbonate minerals and amorphous quartz. Preliminary estimates of the kinetics of the silicate-to-carbonate reactions have been determined experimentally and this research is continuing to determine effects of temperature, pressure, rock composition and mineral assemblages on the reaction rates. This study numerically investigates the injection, migration and sequestration of supercritical carbon dioxide in deep Columbia River basalt formations using the multifluid subsurface flow and reactive transport simulator STOMP-CO2. Simulations are executed on high resolution multiple stochastic realizations of the layered basalt systems and demonstrate the migration behavior through layered basalt aquifers and the mineralization of dissolved carbon dioxide. Reported results include images of the migration behavior, distribution of carbonate formation, quantities of injected and sequestered carbon dioxide, and percentages of the carbon dioxide sequestered by different mechanisms over time.

Investigation of relative flow characteristics of brine-saturated reservoir formation: A numerical study of the Hawkesbury formation

Non-linear stress–strain behaviour of reservoir rock under brine saturation: An experimental study

The subsidence occurring in the Ekofisk field originates from the compaction of the reservoir rock due to the increasing stress placed upon it as reservoir pressure is reduced with production from the field. The mechanical properties of the reservoir rock determine how much compaction will take place for given conditions in the field and are therefore a key factor in determining the degree to which subsidence will occur. These mechanical properties can be combined with other reservoir information (pressure, overburden load, structure, etc.) in simulators to predict the amount of compaction and surface subsidence that will occur in the life of the field. For this to be done accurately, there must be sufficient information to describe the compaction behavior of all the rock within the reservoir for all conditions encountered. The Ekofisk reservoir consists largely of chalk, a very fine-grained, high porosity, mechanically weak rock. A large number of laboratory tests have been run under simulated reservoir conditions to provide a description of the mechanical properties of this chalk. Stress states were applied to reservoir chalk samples to duplicate those encountered in the field, and the resulting compaction was measured. At low stress the chalk compacts elastically with moderate compressibility, but at the higher stress levels encountered in the field during production large amounts of plastic deformation occur. Basic mechanisms of chalk compaction were examined to provide better understanding of the chalk behavior. The chalk properties that primarily influence compaction were identified as porosity and quartz content; the dependence of compaction on these was determined to provide a description of all the chalk within the reservoir. Time dependence of chalk compaction was studied so that laboratory results could be properly applied to the production life of the field. The influence of the waterflooding of the Ekofisk reservoir on the strength of the chalk was studied and found to have no effect. INTRODUCTION The origin of the subsidence in the Ekofisk field is the compaction of the reservoir rock due to production. The effective stress on the rock (the difference between the overburden load on the rock and the pore pressure within the rock) increases as hydrocarbons are withdrawn and reservoir pressure declines. Reservoir rock will compact under these circumstances by an amount determined by its mechanical properties. This compaction can lead to an amount of surface subsidence which is determined by the degree of compaction and the structure and properties of the reservoir and overlying layers. Accurate prediction of subsidence requires that the mechanical properties of the reservoir rock be determined. This can then be combined in simulators with such information as reservoir pressure, overburden properties, and field structure to predict the amount of compaction and resulting surface subsidence which will occur. The objective of the study described here was to determine the mechanical properties of the Ekofisk reservoir rock for use in such simulators. This requires determination of the mechanical properties of all types of rock in the reservoir for all conditions that would be encountered during its production life.

In order to mitigate the greenhouse gas emission level largely in the atmosphere the best possible solution is storing the CO2 in deep saline confined aquifers having impermeable caprock material on the top. However, such deep sedimentary rocks in the presence of water and brine saturation undergo degradation in their mechanical properties – elastic modulus and toughness. Therefore, it is very important to understand and quantify the degree of degradation of mechanical properties of those rocks under varied brine concentration. For this purpose, a detailed experimental work is carried out in this paper. The specimens are saturated under varying brine (0% NaCl to 30% NaCl) and water of different degree of saturation (0% DOS to 100% DOS) saturated sandstone and siltstone rocks, respectively. The rock samples namely, sandstone and siltstone material used in this work collected from Gosford, New South Wales and Eidsvold, Queensland, respectively in Australia. The mechanical properties, namely elastic modulus, E and fracture toughness, KIC estimated using Uniaxial Compressive Strength (UCS) and Three-Point Bending (TPB) tests, respectively. From the powdered X-ray diffraction (XRD) analysis, the sandstone material mineralogical composition has 65.5% quartz, 27.6% kaolinite, 5.4% montmorillonite and 1.4% anatase. Similarly, the siltstone material mineralogical composition has 35% quartz, 53% kaolinite, 8% muscovite, 3% alunite and 1% other minerals.

Mechanical properties have been determined for Ekofisk reservoir rock for use in subsidence simulation. Tests were to describe the mechanical properties of the Ekofisk chalk for reservoir conditions. The mechanisms and time dependence of chalk compaction and the effect of waterflooding on chalk strength were also examined.

Geological Carbon Sequestration (GCS) is one of the ways to store a large quantity of CO2 in a subsurface to combat climate change. The main aim of the thesis is to expand the scope of the element-free Galerkin (EFG) method in its application to multiphase flow for CO2 injection and storage in deep saline aquifers and multiscale modelling of fracture in wet porous media within the linear elastic fracture mechanics domain. Specific objectives include an accurate assessment of stress intensity factors for varying crack lengths and the study of crack propagation in a representative reservoir rock and caprock materials.

CO2 sequestration in deep geological formations is considered as a promising technology to reduce the impact of CO2 on the greenhouse effect. Practically, large-volume of CO2 could be injected into a system that consists of a highly porous host reservoir covered by a low permeable sealing caprock. High rate injection could result in an abrupt fluid pressures build-up, deforming the aquifer and compromising the integrity of the caprock. The interaction between the high-pressure injected CO2 and the host reservoir as well as the cap rock gives rise to a complex engineering system. A good understanding of this coupled interaction is a crucial issue to secure the underground CO2 injection. This thesis is primarily motivated by such need, and the objectives of the present manuscript are to understand and predict the multiphase flow and thermo-hydro-mechanical processes arising from CO2 injection into deep aquifers and to develop and evaluate both analytical and numerical modelling concepts as reliable prediction and risk assessment tools. For the analysis of CO2 injection-induced deformation of the aquifer, a hydromechanical continuum modelling approach is proposed together with a generalised effective stress concept and an elastoplastic description of mechanical rock behaviour. A deep conceptual aquifer is built, and numerical simulations are run to analyses the effects of hydromechanical couplings and injection strategies on the mechanical stability of the aquifer. The results reveal that upon injection geomechanical instabilities originate from the fluid pressure accumulation within the aquifer, and the most important hydromechanical processes occur in the vicinity of the injection well, compromising the caprock integrity. Low-rate injection significantly reduces the fluid pressure accumulation within the aquifer. However, progressively increasing the injection rate to the target value cannot limit the overpressure development significantly. The temperature of injected CO2 is usually lower than the in-situ temperature, providing additional complexity to the hydromechanical coupling. The hydromechanical framework is extended to include multiphase thermo-hydro-mechanical effects. Numerical simulations are carried out 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 performed by the fully coupled simulation is in excellent accordance with the real-time monitoring of the surface uplift at In Salah. A coupled analytical approach is also developed to determine the temporal and spatial evolution of caprock deformation and surface uplift when subjected to CO2 injection. Analytical resolution of the plate theory with the abrupt interface theory led to two closed-form analytical solutions that are validated against both in-situ monitoring data at In Salah and finite element modelling results. This development allows to incorporate any fluid injection-induced pressurisation distribution functions in a straightforward way. Thus, advances in hydrogeology research can be integrated easily, and the current development can be extended to any fluid injection and extraction problem. The proposed approach offers a practical solution for determination of caprock and surface deformation, candidate site evaluation and sensitivity analysis of essential parameters.

Salinity-dependent strength and stress–strain characteristics of reservoir rocks in deep saline aquifers: An experimental study

Costs for carbon dioxide sequestration into deep saline aquifers can be transformed into a benefit when combined with ecologically desirable geothermal heat or power production. The produced energy can be used and marketed. Aim is a scientifically and technically feasible new technology to achieve a safe and economically attractive long-term storage of CO2 trapped in minerals. We develop, study, and evaluate a novel approach not only to sequester CO2 by physical trapping within a reservoir, but to convert dissolved CO2 into the geochemically more stable form of calcite. Due to the geological situation exploitation of geothermal energy in Germany is mainly provided from deep aquifers. The common arrangement of bore holes is the well doublet, consisting of one well for hot water production and one well for cooled water re-injection. The cooled water is loaded with dissolved CO2, and after re-injection into the reservoir this cold water becomes enriched in calcium e.g. due to dissolution of anhydrite (CaSO4). Subsequently CO2 precipitates as calcium carbonate (CaCO3), provided that alkalinity is present either by the dissolution of feldspars in the aquifer or by surface water treatment with fly ashes. Processes are studied both in laboratory and by numerical simulations. The latter are essential to quantify the entire process of CO2 storage and to deepen the understanding of the detailed chemical processes. Reaction modelling and reactive transport simulations are done on multiple scales since the combination of all scales is not feasible in numerical models up to now. The relevant scales studying CO2 storage in combination with geothermal energy production reach down from the reservoir scale (ca. 10 km) to the micro scale (ca. 1 cm). Results from larger scale models provide constraints for smaller scale scenarios. For processes which cannot be resolved on the larger scale, due to restrictions of discretization of the applied numerical mesh, functionalities are derived from the smaller scale. To be predictive and capable of quantifying amounts of storable CO2 numerical investigations on the reservoir scale are vital. Simulations on the borehole scale are necessary, because the near vicinity of wells is vulnerable to permeability decrease as a result of mineral reactions. Laboratory experiments are used to calibrate the numerical tools and simulations on the micro scale allow further investigation of the overall process of mineral dissolution and precipitation. Simulation results as well as laboratory experiments prove that anhydrite can be successfully transferred into calcite and thus are evidence for the feasibility of the new technology.

Reducing the amount of carbon dioxide in the atmosphere is vital to mitigate climate change. To date reduction efforts have primarily focused on minimizing the production of carbon dioxide during electricity generation, transport, and other activities. Going forward, to the extent that carbon dioxide continues to be produced, it will need to be captured before release. The captured carbon dioxide can then be utilized in some fashion, or it can be injected into underground geological formations – e.g., depleted oil and gas reserves, deep saline aquifers, or basalt rock reservoirs – where, it is hoped, it will remain permanently sequestered (“carbon capture and storage” or “CCS”). Research is currently being undertaken into the possibility of injecting carbon dioxide into the seabed. One study, involving researchers from Columbia’s Lamont-Doherty Earth Observatory, aims to identify possible injection sites in the seabed along the northeast coast of the U.S. It is anticipated that, following identification of suitable sites, a demonstration project will be undertaken to assess the feasibility of offshore CCS. This paper outlines key regulatory requirements for the demonstration project and any subsequent commercial operations.

The determination of effective carbon dioxide (CO2) permeability in reservoir rock and its variation is of great interest in the process of CO2 sequestration in deep saline aquifers, as CO2 sequestration-induced permeability alternations appear to create major problems during the CO2 injection process. The main objective of this study is to investigate the effect of salinity on the effective CO2 permeability of reservoir rock under different injection pressures. A series of high-pressure tri-axial experiments was, therefore, performed to investigate the effect of salinity on effective CO2 permeability in Hawkesbury sandstone under various brine concentrations. The selected brine concentrations were 0, 10, 20, and 30 % sodium chloride (NaCl) by weight and the experiments were conducted for a range of CO2 injection pressures (2, 4, 6, 8, 10, and 12 MPa) at a constant confinement of 20 MPa and a temperature of 35 °C, respectively. According to the results, the degree of salinity of the aquifer’s pore fluid plays a vital role in the effective CO2 permeability variation which occurs with CO2 injection, and the effective permeability decreases with increasing salinity in the range of 0–30 % of NaCl. Interestingly, in dry reservoir rock samples, the phase transition of the injection of CO2 from gas to super-critical condition caused a sudden reduction of CO2 permeability, related to the slip flow effect which occurs in gas CO2. Transfer into vapor or super-critical CO2 causes this slip flow to be largely reduced, reducing the reservoir permeability for CO2 movement in dry reservoir rock samples. However, this behavior was not observed for water- and brine-saturated samples, and an increasing trend of effective CO2 permeability was observed with increasing injection pressure. A detailed chemical analysis was then conducted to understand the physical phenomenon causing the salinity effect on effective CO2 permeability using scanning electron microscopy analyses. Such analyses explain the reason for the observed permeability variations by giving detailed images of the rock sample’s microstructure. There were clear depositions of NaCl crystals in the rock’s pore space, and the amount increased with increasing brine concentration.

Storage of carbon dioxide (CO2) by precipitation of carbon-bearing minerals in geological formations is, on the long run, more stable and therefore much safer than direct storage or solution trapping. Among available options for CO2 sequestration that are particularly attractive are those that offer additional economic benefits apart from the primary positive effect for the atmosphere (e.g., enhanced gas or oil recovery), such as the novel approach of storing dissolved CO2 as calcite in managed geothermal aquifers. Hydrogeothermal energy in Germany is mainly provided from deep sandstone aquifers by a so-called doublet installation consisting of one well for hot water production and one well for injection of the cooled water. When cold brines are enriched with CO2 and injected into an anhydrite-bearing reservoir, this mineral dissolves. As a result, the water becomes enriched in calcium ions. Numerical simulations demonstrate that dissolved Ca and CO2 react to form and precipitate calcium carbonate provided that alkaline buffering capacity is supplied from plagioclase in the reservoir rock or by surface water treatment with fly ashes. We show that anhydrite dissolution with the concurrent pore-space increase is important to balance pore-space reduction by precipitation of calcite and secondary silicates. Laboratory experiments prove the feasibility of transforming anhydrite into calcite and provide necessary kinetic input data for the modeling. Suitable geothermal reservoirs exist, which contain sufficient anhydrite as matrix mineral and plagioclase for supplying alkalinity. Mass balance calculations performed with respect to the anhydrite and feldspar content show that, for an assumed operation time of 30 yr, the theoretical storage capacity is significant: millions of tons of CO2 can be trapped as calcite in geological formations used by geothermal heating plants.

This study examines the geomechanical effects of depleted oil and gas reservoir rocks during underground hydrogen storage (UHS), with a specific focus on the Red River Formation in North Dakota. As the transition to renewable energy sources accelerates, hydrogen storage in geological formations presents a promising solution for large-scale energy storage. However, numerous challenges and barriers exist that prevent this technology from becoming a widely available decarbonization solution. The UHS process comprises multiple cycles of injection and withdrawal. These cycles may elevate the risk of fracturing or seal integrity failure in certain reservoirs. Furthermore, it is crucial to assess the potential alteration of rocks caused by hydrogen exposure to understand its impact on the mechanical properties of the reservoir rock and caprock. This study investigates the effect of geomechanical change in the mechanical and petrophysical properties of reservoir rock and caprock rocks (Carbonate + Anhydrite), crucial factors for securing subsurface hydrogen containment. Core samples from three wells in the Red River Formation's Zone B were subjected to high-pressure, high-temperature (HPHT) conditions simulating underground storage environments, including 30-day hydrogen exposure at 2000 psi and 140°C. Advanced analytical techniques including Nuclear Magnetic Resonance (NMR) porosity measurements, pulse-decay permeability analysis, and ultrasonic velocity measurements were employed to assess geomechanical changes before and after hydrogen exposure. The results revealed distinct lithological control on hydrogen-rock interactions with favorable implications for storage integrity. Carbonate reservoir samples demonstrated systematic porosity increases ranging from 9.7% to 23.1%, with corresponding permeability enhancements of 12.7% to 25.8%. Despite these petrophysical changes, mechanical properties showed improvement, with dynamic Young's modulus increasing by 1.7% to 11.4% and compressional wave velocities enhancing by 8.6% to 30.1%. Poisson's ratio increased by 3.6% to 13.7%, indicating altered deformation characteristics that remain within acceptable operational ranges. Anhydrite caprock samples exhibited exceptional stability and enhanced sealing capacity under hydrogen exposure. Porosity changes were negligible (±2%), while permeability remained ultra-low with minimal variations (±4.5%). Remarkably, caprock mechanical properties showed significant strengthening, with Young's modulus increasing by 10.4% to 18.3% and compressional wave velocities improving by up to 22.1%. These enhancements indicate improved structural integrity and resistance to deformation under operational pressures. The systematic mechanical property improvements in both reservoir and caprock formations create a geomechanically favorable environment for hydrogen storage operations. These findings advance the understanding of geomechanical processes in UHS and provide crucial insights supporting the safe and efficient implementation of hydrogen storage in depleted carbonate reservoirs with anhydrite seals, particularly in similar geological settings throughout the Williston Basin.