ARMA 17-199 Clay-rich rocks as barriers for geologic CO 2 storage

In geologic CO2 storage, it is important to find a proper barrier material that will avoid or limit acidic fluid migration. Shales that are ductile and have high capillary entry pressure and low permeability can be considered as good candidates for the caprock. Faults may contain high percentage of clay and act as barriers for fluid flow in reservoirs. Experimental techniques have been developed to characterize the behavior of clay-rich materials at elevated pressures. Intact and remolded specimens of Opalinus clay – a Jurassic shale from Switzerland – are brought to the conditions of deep (> 1 km depth) geologic storage and fully saturated with in-situ brine. Poromechanical parameters and failure characteristics are measured in drained and undrained conventional triaxial compression experiments. CO2 breaktrough pressure and permeability of shale are assessed in oedometric tests on thin (12 mm) samples. Experimentally measured parameters are used in numerical simulations to assess fault stability and the shaly caprock integrity for the case of geologic carbon storage, where cooling is likely to occur around injection wells. It is found that clay-rich faults may induce microseismic events, but without leading to CO2 leakage. Another source of concern are faults (Rutqvist et al., 2016). Fault architecture is complex and may behave either as a barrier or a conduit (Caine et al., 1996). Faults with a large offset may contain a high percentage of clay and act as barriers for fluid flow in reservoirs (Benson and Person, 2006). This barrier effect leads to pressure buildup and subsequent stress changes that may reduce fault stability and eventually induce felt seismicity (Vilarrasa et al., 2016). Even for a small fault offset, permeability across the fault in reservoir sections may decrease as a result of mineral precipitation after hydrothermal water circulation. As for fault permeability in the caprock sections, shear failure may induce an increase in permeability with respect to that of the intact rock, though the creation of conduits for CO2 upward migration is unlikely due to caprock ductility (Laurich et al., 2014; Bourg, 2015). Opalinus clay (a Jurassic shale from Switzerland) is considered to be a representative caprock material because of its high (~60%) clay content and very small dominant pore size (~30 nm). Injection of CO2 inside low-permeable clayey specimens, their relative permeability to brine and CO2, and CO2 breakthrough pressure are discussed in Makhnenko et al. (2017). Poromechanical properties of the shale are analysed by performing drained, undrained, and unjacketed conventional triaxial tests (Räss et al., 2017). Thermo-hydro-mechanical response of the caprock due to cooling is discussed in Vilarrasa et al. (2015a), who showed that a potential shallow (~1 km) storage case with cold CO2 injection leading to caprock cooling by 20 ̊C (from 40 ̊C to 20 ̊C) does not compromise shale’s integrity. Additionally, shales show interesting selfsealing features and their ductile-type failure often allows to retain very small permeability. Viscous (timedependent) deformation may become significant when assessing the long-term caprock integrity. Creep of Opalinus clay was found to accelerate with temperature and pore fluid pressure raise, which increases the probability of porosity wave creation (Räss et al., 2017). The overarching goal of this study is to identify the main challenges for caprock integrity (e.g., temperature and chemical effects, long-term permeability, and strength evolution) and to study them both experimentally and numerically for a caprock representative. In addition to our previous laboratory studies on intact shale, we have carried out new experiments on remolded (reconstituted) Opalinus clay that is more permeable and represents a fault material. Once the properties of the rock are determined from laboratory experiments, we model CO2 injection into an extensive aquifer crossed by a lowpermeable fault to assess caprock integrity and discuss the implications for deep geologic storage. 2. EXPERIMENTAL TECHNIQUES Experimental techniques have been developed to characterize shale behavior. Intact and remolded Opalinus clay specimens are brought to the conditions of deep (> 1 km depth) geologic storage and fully saturated with in-situ brine. The back pressure saturation method is implemented with graduate increase of upstream and downstream pressures, p, and promoting the flow through low-permeable (~ 10 m) specimens. It allows achieving full saturation (at p > 7 MPa) that is confirmed by measurements of constant Skempton’s B coefficient values while the effective mean stress is preserved to be the same. Recorded undrained pore pressure increments are corrected for the influence of “dead” volume (Makhnenko and Labuz, 2016). One of the critical parameters for the barrier sealing efficiency is the breakthrough pressure, i.e., the excess of non-wetting fluid (e.g., CO2) pressure above initial pore fluid pressure that is enough to initiate its flow through the sealing layer. Tests on thin (12 mm in height and 35 mm in diameter) shale specimens loaded under oedometric conditions allowed evaluating the breakthrough pressure and permeability for liquid (24 oC) and supercritical CO2 (42 oC). Use of thin specimens significantly facilitates saturation and flow tests in low-permeable materials, because the timescale for pore pressure diffusion is proportional to the characteristic specimen length squared. The breakthrough pressure for liquid and supercritical CO2 is measured using two different methods: direct (with the establishment of continuous CO2 flow) and indirect (through a residual capillary pressure evaluation). Brine and CO2 permeability of shale is reported from steadystate flow tests performed at fixed differential pressure for at least three days (Makhnenko et al., 2017). Poroelastic parameters are measured in drained and undrained conventional triaxial compression experiments with specimens of 50 mm in diameter and 100 mm in height (Makhnenko and Labuz, 2016; Räss et al., 2017). Drained and undrained heating and cooling tests provide the corresponding thermal expansion coefficients. Upon completion of elastic parameters’ measurements, intact and remolded shale specimens are loaded to failure. Undrained tests at different effective confining pressures provide failure data to evaluate cohesion and friction of tested rocks. Considering the characteristic timescale to guarantee pore pressure equilibration in triaxial tests, the overall duration of each test that included back pressure saturation process, measurements of elastic properties, and loading to failure is 4-6 weeks. Fig. 2. Overview of the tests performed on clay-rich materials. 3. MODEL FORMULATION We model CO2 injection in a deep saline aquifer that is crossed by a low-permeable fault (Figure 3). The fault dips 60o and is formed by a fault core and a damage zone on both sides of the core. While the fault core has the same properties along the whole fault, the damage zone has different properties for each rock type. We assume that CO2 is injected through a horizontal injection well that is parallel to the fault, so we model a 2D plane strain cross section. The injection well, which is placed 5 m above the bottom of the injection formation, is located 1 km away from the fault. The model extents laterally for 15 km to each side of the fault. The storage formation, which represents Berea sandstone, overlays (base rock) and is overlain (caprock) by Opalinus clay, which properties vary slightly as a function of depth. Below the base rock, we model the upper 100 m of the crystalline basement, which is made of Charcoal granite. Above the caprock, another saline aquifer, made of Indiana limestone, is included in the model. The top of this upper aquifer is placed at a depth of 1,275 m. The geological layers above this aquifer are not included in the model, but its equivalent weight is applied as an overburden at the top of the model. We consider a normal faulting stress regime that is coherent with the presence of the steep fault. The vertical stress is given by the weight of the rock, which is considered to have an average of 23 MPa/km. The horizontal stresses are H = h = 0.69v. The mechanical boundary conditions are given by a constant vertical stress at the top of the model equal to 29.3 MPa and no displacement perpendicular to the lateral and bottom boundaries. We consider a temperature of 60 oC, which corresponds to a surface temperature of 10 oC and the geothermal gradient of 33 oC/km at 1.5 km, i.e., the depth of the storage formation. Water pressure is assumed to be hydrostatic and constant pressure boundary conditions are applied at the lateral boundaries. At the well, CO2 is injected at a rate of 2.0·10 kg/s/m for 1 year. We solve this hydro-mechanical problem in a fully coupled way. The hydraulic problem is governed by mass and momentum conservation of each phase, i.e., water and CO2. Mass conservation of each fluid is given by     w c r t S , ,           