Nanograin formation and reaction-induced fracturing due to decarbonation: Implications for the microstructures of fault mirrors

Principal slip zones often contain highly reflective surfaces referred to as fault mirrors, shown to consist of a nanogranular coating. There is currently no consensus on how the nanograins form, or why they survive weathering on a geological time-scale. To simplify the complex system of a natural fault zone, where slip and heat generation are inherently coupled, we investigated the effect of elevated temperatures on carbonate rock surfaces, as well as their resistance to water exposure. This allows us to isolate the role of the decarbonation process in the formation of nanograins. We used cleaved crystals of Iceland spar calcite, manually polished dolomite protolith, as well as natural dolomite fault mirror surfaces. The samples were heated to 200–800 °C in a ∼5 h heating cycle, followed by slow cooling (∼12 h) to room temperature. Subsequently, we imaged the samples using scanning electron microscopy and atomic force microscopy. Nanograin formation on all sample surfaces was pervasive at and above 600 °C. The Foiana fault mirror samples were initially coated with aligned naturally-formed nanograins, but display a non-directional nanogranular coating after heating. The nanograins that were formed by heating rapidly recrystallized to bladed hydroxides upon exposure to deionized water, whereas the nanograins on unheated fault mirror samples remained unchanged in water. This shows that the nanograins formed by heating alone are different from those formed in fault zones, and calls for a better characterization of nanograins and their formation mechanisms. Furthermore, we find a characteristic star-shaped crack pattern associated with reacted regions of the carbonate surfaces. The existence of this pattern implies that the mechanical stresses set up by the decarbonation reaction can be sufficiently large to drive fracturing in these systems. We propose that this mechanism may contribute to grain size reduction in fault zones

Healing and sliding stability of simulated anhydrite fault gouge : Effects of water, temperature and CO2

Anhydrite-bearing faults are currently of interest to 1) CO2-storage sites capped by anhydrite caprocks (such as those found in the North Sea) and 2) seismically active faults in evaporite formations (such as the Italian Apennines). In order to assess the likelihood of fault reactivation, the mode of fault slip and/or fault leakage, it is important to understand the evolution of frictional strength during periods of no slip and upon reloading (healing and relaxation behavior) and of the velocity dependence of friction of anhydrite fault gouge. Therefore, we performed slide–hold–slide experiments combined with a velocity-stepping sequence using simulated anhydrite fault gouge (> 95 wt.% CaSO4). Vacuum-dry and water-wet experiments were performed at temperatures ranging from 20 to 150 °C, and at an effective normal stress of 25 MPa. We also performed tests using dry CO2, water-wetted CO2 and CO2-saturated water as pore fluid, but only at 120 °C. If pore fluid was present, a fluid pressure of 15 MPa was present. Vacuum-dry samples exhibit similar frictional healing to samples containing lab-air, but healing is significantly enhanced in wet samples. Dry samples exhibit velocity-weakening behavior at T ≥ 120 °C, and wet samples exhibit velocity-strengthening behavior over the full temperature range. The presence of CO2 does not influence the healing behavior or the velocity-dependence of friction. Samples containing water-wetted CO2 exhibit behavior similar to wet samples. We infer that the healing in dry samples is controlled by plastic asperity creep (Dieterich-type), possibly through dislocation creep and/or twinning. In wet samples healing is inferred to be controlled by increases in contact area and cohesion by pressure solution. Using a pressure solution rate model to extrapolate healing by contact area growth indicates that the maximum re-strengthening through such a mechanism will only take days to tens of days

Healing and sliding stability of simulated anhydrite fault gouge: Effects of water, temperature and CO2

Anhydrite-bearing faults are currently of interest to 1) CO2-storage sites capped by anhydrite caprocks (such as those found in the North Sea) and 2) seismically active faults in evaporite formations (such as the Italian Apennines). In order to assess the likelihood of fault reactivation, the mode of fault slip and/or fault leakage, it is important to understand the evolution of frictional strength during periods of no slip and upon reloading (healing and relaxation behavior) and of the velocity dependence of friction of anhydrite fault gouge. Therefore, we performed slide–hold–slide experiments combined with a velocity-stepping sequence using simulated anhydrite fault gouge (> 95 wt.% CaSO4). Vacuum-dry and water-wet experiments were performed at temperatures ranging from 20 to 150 °C, and at an effective normal stress of 25 MPa. We also performed tests using dry CO2, water-wetted CO2 and CO2-saturated water as pore fluid, but only at 120 °C. If pore fluid was present, a fluid pressure of 15 MPa was present. Vacuum-dry samples exhibit similar frictional healing to samples containing lab-air, but healing is significantly enhanced in wet samples. Dry samples exhibit velocity-weakening behavior at T ≥ 120 °C, and wet samples exhibit velocity-strengthening behavior over the full temperature range. The presence of CO2 does not influence the healing behavior or the velocity-dependence of friction. Samples containing water-wetted CO2 exhibit behavior similar to wet samples. We infer that the healing in dry samples is controlled by plastic asperity creep (Dieterich-type), possibly through dislocation creep and/or twinning. In wet samples healing is inferred to be controlled by increases in contact area and cohesion by pressure solution. Using a pressure solution rate model to extrapolate healing by contact area growth indicates that the maximum re-strengthening through such a mechanism will only take days to tens of days

Laboratory experiments on the effects of corrosion inhibitor on the mechanical properties of reservoir rock

Abstract Geothermal energy production often involves use of corrosion inhibitors. We performed rock mechanical experiments (room temperature; confining pressure of 10/20/30 MPa) on typical reservoir rocks (Bentheim sandstone and Treuchtlinger limestone) in contact with two different inhibitor solutions or with demineralized water. The sandstone experiments show no discernible difference in rock strength between inhibitors or water, attributed to low quartz reactivity. The limestone experiments show a significant difference in rock strength (and Mohr–Coulomb envelope), dependent on inhibitor type, attributed to high carbonate reactivity. This implies that, depending on the reactivity of the rocks and local stress conditions, inhibitor leakage may lead to unpredicted reservoir failure

Reactivation envelopes of immature and mature faults of Dinantian carbonates targeted for geothermal energy

Applied Geophysics and Petrophysic

Effects of temperature and CO2 on the frictional behavior of simulated anhydrite fault rock

The frictional behavior of anhydrite‐bearing faults is of interest to a) the safety and effectiveness of CO2 storage in anhydrite‐capped reservoirs, b) seismicity induced by hydrocarbon production, and c) natural seismicity nucleated in evaporite formations. We performed direct shear experiments on simulated anhydrite fault gouges, at a range of temperatures (80‐150 °C) and sliding velocities (0.2‐10μms−1), under a fixed effective normal stress of 25 MPa. Four types of experiments were conducted: 1) dry experiments, 2) experiments pressurized with water, 3) dry experiments pressurized with CO2, and 4) wet experiments pressurized with CO2. Fluid pressures of 15 MPa were used when applied. Over the temperature range investigated water‐saturated samples were found to be up to 15% frictionally weaker than dry equivalents. Wet samples containing CO2 were also up to 15% weaker than CO2‐free equivalents. Dry sample strength without CO2 was independent of temperature, whereas wet samples without CO2 strengthened 10% from 80 to 150 °C. Samples containing CO2 weakened by 4% (dry) and 10% (wet) from 80 to 150 °C. Under the P‐T conditions investigated, only dry anhydrite fault gouge showed velocity‐weakening behavior above 120 °C, required for faults to potentially generate earthquakes. Assuming natural fault gouges are wet in‐situ, seismicity is unlikely to nucleate in anhydrite‐rich faults, though the presence of dolomite or reaction‐produced calcite may change seismic potential. CO2 penetration into wet anhydrite‐rich faults may trigger slip on critically stressed faults due to the observed short‐term CO2 weakening effects (excluding possible formation of secondary minerals), but is not expected to influence slip stability

How microfracture roughness can be used to distinguish between exhumed cracks and in-situ flow paths in shales

Flow through fractures in shales is of importance to many geoengineering purposes. Shales are not only caprocks to hydrocarbon reservoirs and nuclear waste or CO2 storage sites, but also potential source and reservoir rocks for hydrocarbons. The presence of microfractures in shales controls their permeability and transport properties. Using X-ray micro-tomography and white light interferometry we scanned borehole samples obtained from 4 km depth in the Pomeranian shales in Poland. These samples contain open exhumation/drying cracks as well as intact vein-rock interfaces plus one striated slip surface. At micron resolution and above tensile drying cracks exhibit a power-law roughness with a scaling exponent, called the Hurst exponent H, of 0.3. At sub-micron resolution we capture the properties of the clay interface only, with H = 0.6. In contrast, the in-situ formed veins and slip surface exhibit H = 0.4–0.5, which is deemed representative for in-situ fractures. These results are discussed in relation to the shale microstructure and linear elastic fracture mechanics theory. The data imply that the Hurst roughness exponent can be used as a microstructural criterion to distinguish between exhumation and in-situ fractures, providing a step forward towards the characterization of potential flow paths at depth in shales

A high resolution interferometric method to measure local swelling due to CO\u3csub\u3e2\u3c/sub\u3e exposure in coal and shale

\u3cp\u3eWe present an experimental method to study time-dependent, CO\u3csub\u3e2\u3c/sub\u3e-induced, local topography changes in mm-sized composite samples, plus results showing heterogeneous swelling of coal and shale on the nano- to micrometer scale. These results were obtained using high resolution interferometry measurements of sample topography, combined with a new type of experimental microfluidic device. This device is a custom-built pressure vessel, which can contain any impermeable sample type and can be placed under any microscope. The pressure vessel itself has been tested to handle pressures up to 100 bar at room temperature conditions. For the experiments reported here we used three sample types: i) epoxy and dolomite, ii) coal, epoxy and dolomite and iii) shale. These model systems (thicknesses between 2 and 10 mm) were exposed to pressurized CO\u3csub\u3e2\u3c/sub\u3e (20–35 bars) and subsequently deformation over time was monitored with a white light interferometer. This provided a lateral spatial resolution of 979 nm and a vertical spatial resolution of 200 nm, i.e. sufficient resolution so that coal and shale constituents can be tracked individually. Within 72 h epoxy swells homogeneously up to 11 μm, coal swells 4 ± 1 μm and dolomite is unreactive with the dry CO\u3csub\u3e2\u3c/sub\u3e injected here, and as such is used as a reference surface. The differential swelling of coal can be correlated in space with the macerals, where macerals with an initial higher topography swell more. The average or bulk swelling exhibits an approximate t\u3csup\u3e½\u3c/sup\u3e relation, indicative of diffusion-controlled adsorption of CO\u3csub\u3e2\u3c/sub\u3e on the organic matter. Measurements of the differential swelling of both shale samples enabled tracking of individual patches of organic matter within the shale (max. 20 × 20 μm). These patches exhibit finite swelling of on average 250 nm in 4 h (in the Pomeranian shale) and 850 μm in 20 h (in the Green River shale), where total swelling is assumed to be related to the volume of the patches of organic matter.\u3c/p\u3

Development of Tailored Wellbore Sealants for CCS and Other Geological Storage Applications

The development of new geological storage applications and other uses of subsurface reservoirs requires tailored wellbore sealants, able to withstand application-specific exposure conditions. For example, wellbore sealants used in reservoirs targeted for CO2-storage will be exposed to CO2-rich fluids, that may chemically attack OPC-based sealants, leading to carbonation and potential degradation. During CO2-injection, local temperature changes around the injection well may also affect the integrity of the sealant-wellbore system, for example causing the formation of annuli between sealant and steel casing due to differences in thermal expansion. The research project CEMENTEGRITY aims to identify the key sealant properties that may help to ensure the long-term integrity of the wellbore-seal system during CO2-injection and storage, as well as the best testing methods for these properties. This is done by testing five different sealant compositions, exposing them to potentially deleterious impacts under different conditions. Here, we report some of the key findings of our project. While CEMENTEGRITY is researching sealants specifically for CO2-storage, other applications, such as hydrogen storage, or geothermal energy exploitation, will require purpose-built sealants that are similarly tailored to the expected chemical and physical conditions