Caprock Stability Research Articles

Mixed-layer illite–smectite reactivity in acidified solutions: Implications for clayey caprock stability in CO 2 geological storage

The reactivity of mixed-layer illite–smectite was investigated in batch and mixed-flow reactors in the presence of K-bearing mineral impurities (K-feldspar) in order to determine the reaction pathways and the kinetic rate of the reactions in a range of pH conditions pertinent to the context of CO 2 geological storage. The mixed-layered illite–smectite (I–S) mineral was extracted from a natural clayey caprock and was studied at 80 °C, with a solution salinity of 0.1 M NaCl and over a pH range from 3 to 8.5. The experimental results show that the most important process taking place is illitization of the initial I–S. In the most acidic conditions, an intense illitization is observed, which was interpreted as a new proton-promoted illitization process. At neutral pH, illitization is less intense and is attributed to a classical thermal effect. In terms of the overall reaction rate (I/S and K-feldspar dissolution in a mixed flow experiment), the values calculated from the evolution of SiO 2 concentrations fall in the range of the experimental values reported in the literature for smectites and illites. Implications of illitization processes on CO 2 storage and clayey caprock integrity are also discussed.

Geomechanical stability of the caprock during CO2 sequestration in deep saline aquifers

Sequestration of carbon dioxide (CO2) in deep saline aquifers has emerged as a mitigation strategy for reducing greenhouse gas emissions to the atmosphere. The large amounts of supercritical CO2 that need to be injected into deep saline aquifers may cause large fluid pressure buildup. The resulting overpressure will produce changes in the effective stress field. This will deform the rock and may promote reactivation of sealed fractures or the creation of new ones in the caprock seal, which could lead to escape paths for CO2. To understand these coupled hydromechanical phenomena, we model an axisymmetric horizontal aquifer-caprock system. We study plastic strain propagation patterns using a viscoplastic approach. Simulations illustrate that plastic strain may propagate through the whole thickness of the caprock if horizontal stress is lower than vertical stress. In contrast, plastic strain concentrates in the contact between the aquifer and the caprock if horizontal stress is larger than vertical stress. Aquifers that present a low-permeability boundary experience an additional fluid pressure increase once the pressure buildup cone reaches the outer boundary. However, fluid pressure does not evolve uniformly in the aquifer. While it increases in the low-permeability boundary, it drops in the vicinity of the injection well because of the lower viscosity of CO2. Thus, caprock stability does not get worse in semi-closed aquifers compared to open aquifers. Overall, the caprock acts as a plate that bends because of pressure buildup, producing a horizontal extension of the upper part of the caprock. This implies a vertical compression of this zone, which may produce settlements instead of uplift in low-permeability (k≤10-18 m2) caprocks at early times of injection.

The fluidal interface is where the action is in CO2 sequestration and storage: Hydromechanical analysis of mechanical failure

Abstract In this paper, conceptual modeling and numerical simulation of two-phase flow during CO2 injection into deep saline aquifers is presented. The work focuses on isothermal transport and deformation processes in the vicinity of the injection well including hydromechanical failure analysis. Governing differential equations are based on balance laws for mass and momentum completed by constitutive relations for the fluid and solid phases as well as their interactions. Constraint conditions for the partial saturations and the pressure fractions of CO2 and brine are defined. To characterize the stress state in the solid matrix the effective stress principle is applied. The coupled problem is solved using an in-house scientific finite element code, and verified with benchmarks. In terms of application-oriented aspects, we examine the mechanical integrity of a deep saline aquifer during the injection of supercritical CO2. The analysis is conducted with a numerical scheme of the capillary pressure and non-wetting phase pressure for the two-phase flow process. In this study, unidirectional hydromechanical coupling is considered. Caprock stability is monitored in time, referenced to the potential for hydraulic fracture and shear slip along an optimally oriented shear plane for a suite of injection pressures. For reasonable parameter values and the chosen aquifer geometry, significant mechanical failure (and potential breach of integrity) is expected in the shale caprock for all but low injection rates. This indicates that the analysis of the hydromechanical response is crucial for proper selection of injection sites, injection rates, and total storage capacity.

Sensitivities of injection rates for single well CO 2 injection into saline aquifers

This paper investigates methods to predict potential injection rates of CO 2 into a saline aquifer and analyses the sensitivities of the input parameters. Geological parameters are based on conditions at the European CO 2 Onshore Research Storage and Verification Project in Ketzin, Germany, and varied within an acceptable range. Two injection regimes for CO 2 are analysed: pressure controlled injection and power plant controlled injection, where the CO 2 flux depends on the load curve of a 600 MW net lignite power plant. The results are determined with a numerical model and compared to an analytical solution with constant pressure injection. The injection rates depend mainly on the geological setting and only slightly on technical parameters. Aquifer permeability and thickness show approximately linear sensitivity and have a dominant impact. Depth is also of high importance, but the impact is more complex and is based on geothermal temperature and hydrostatic gradient, which affect viscosity, compressibility and caprock stability. Vertical anisotropy is insensitive. The difference in the mean rate between constant pressure injection and power plant controlled injection is 8%. Peak injection rates are 29% above mean injection rates, which shows that the reservoir can effectively dampen rate variations. The analytical solution predicts the highest injection rates, the lowest temporal variability and decreasing rates with injection duration. The numerical solution predicts a stronger temporal variability and the rates increase with duration. In the initial phase the differences between the methods add up to a factor of 1.45.