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Microstructural, Geomechanical, and Petrophysical Characterization of Shale Caprocks

David N. Dewhurst, Claudio Delle Piane, Lionel Esteban, Joel Sarout, Matthew Josh, Marina Pervukhina, and M. Ben Clennell

CSIRO Energy, Perth, Australia

ABSTRACT

Geological storage of carbon dioxide requires extensive characterization of potential selected sites in terms of injectivity, storage capacity, and containment integrity. The latter item on that list requires a multi‐scale evaluation of all aspects of the subsurface geology that can trap CO2 underground and keep it there long term. One part of a containment integrity strategy includes characterization of the caprock at a given site. Many selected sites have clay‐rich shales as caprocks, and this contribution will concentrate on workflows and methods for characterizing such rocks in the laboratory. Shale preservation is the most critical step in the process as dehydration from the native in situ water content significantly affects shale properties. Various mineralogical, microscopical, petrophysical, and geomechanical properties and associated testing methods are discussed, and where possible, examples are shown of the impact of lack of preservation. Results are discussed in the context of interaction of CO2 with caprocks and trapping mechanisms. Finally, the discussion looks at a number of the uncertainties associated with laboratory testing of shales in terms of both results obtained to date and our limited understanding as yet of the behavior and interaction of supercritical CO2 with clay‐rich caprocks.

1.1. INTRODUCTION

Geological storage of carbon dioxide (CO2) has been mooted as a greenhouse gas mitigation strategy for over 20 years. The practical mechanics of such a strategy have been tested out at small scale at sites such as the Otway Basin in Australia [Sharma et al., 2009] and Frio in Texas [Doughty et al., 2008] and during industrial‐scale projects, for example, at Sleipner [Arts et al., 2008] and In Salah [Ringrose et al., 2013]. Many years of effort have been put into defining the critical parameters for potential CO2 storage sites [e.g., IPCC, 2005], and these include depth, storage capacity of the site, injectivity of the reservoir, and the containment integrity of the structure into which the CO2 is injected. Containment integrity is usually thought of in similar terms as traps and seals in petroleum systems, and similar technologies can be used to evaluate the properties of the fault and/or top seals that provide the trapping mechanisms for keeping injected CO2 in the deep subsurface. Fault seals usually result from the incorporation of material into the fault zone during fault movement, and this can comprise smearing out of ductile clay‐rich units, abrasion of harder shales, cataclasis of rigid grains, and syn‐/post‐kinematic cementation of the fault rock products [e.g., Lindsay et al., 1993; Yielding et al., 1997; Fisher and Knipe, 1998; Dewhurst et al., 2005]. Top seals are usually characterized in terms of their thickness (especially in relation to fault throw), areal extent, seal capacity (pore‐scale capillary properties), and seal integrity (mechanical properties). There are multiple techniques for assessing the potential sealing capacity of faults [e.g., Watts, 1987; Lindsay et al., 1993; Yielding et al., 1997], and these will not be discussed further here. This paper will concentrate on methods that can be used to characterize caprocks in the laboratory and the relationship between these measurement techniques and the properties noted above. In this contribution, we will concentrate on shale‐rich caprocks but acknowledge that other rocks such as anhydrites [e.g., Hangx et al., 2010] are being evaluated as caprocks for CO2 storage sites. However, it should be emphasized that any seal evaluation for a storage site or petroleum prospect should be fully integrated across both fault and top seals and for a wide range of scales.

Shale caprock properties are dependent on a number of factors, including depositional environment and resultant lithology, electrochemical conditions at deposition, mineralogy, the presence of organic matter, compaction, and diagenetic alteration. All of these processes have a significant impact on porosity and permeability, as well as the mechanical, capillary, and petrophysical properties of shales [e.g., Bennett et al., 1991a,b; Vernik and Liu, 1997; Dewhurst et al., 1998, 1999a, 1999b; Clennell et al., 2006]. A number of these properties are also controlled by human intervention during and after the coring process, such as stress relief microfracture development and drying out and desiccation of recovered core, and care must be taken for certain properties that adequate sample preservation is undertaken [e.g., Schmitt et al., 1994; Dewhurst et al., 2012; Ewy, 2015]. This study will therefore review possible preservation methods and discuss multiple mechanical and petrophysical characterization techniques that can be used to either directly measure or estimate relevant properties required for shale caprocks.

1.2. SHALE PRESERVATION

The most critical stage for deriving high‐quality laboratory results from shales is their immediate preservation on recovery. Loss of pore water from the in situ state can result in changing mechanical, physical, and petrophysical properties [Schmitt et al., 1994] no matter whether the shale is soft, weak, and ductile or hard, strong, and brittle. Some pore fluid will always be lost from shales on recovery due to outgassing as cores are depressurized from the in situ conditions to the Earth's surface [Schmitt et al., 1994]. However, most techniques that look to measure mechanical and rock physics properties, for example, would look to test the shale using a chemically compatible pore fluid under pressure, and this would generally drive any air into solution at fluid pressures >0.5 MPa. Running such tests under undrained conditions at low strain rates (< 10−7 s−1) allows monitoring of the pore pressure response either through Skempton B tests [Skempton, 1954] or during axial loading. Pore pressure increase under such conditions is indicative of full saturation. Hence, the slight loss of pore fluid during recovery can be alleviated for such tests. Equilibrating in relative humidity (RH) environments equivalent to shale native water activity can also mitigate this effect [e.g., Steiger and Leung, 1991; Ewy, 2014]. Other tests such as composition via X‐ray diffraction (XRD), cation exchange capacity (CEC), or specific surface area (SSA) measurements generally would not be significantly affected by core preservation, although one should be careful to verify whether the presence of salts (e.g., halite, sylvite) or gypsum is real or artifacts of core storage [e.g., Milliken and Land, 1994].

Ideally, fully saturated core samples should be preserved under a nonpolar mineral spirit (e.g., Ondina 15 or Ondina 68) such that the fluid does not interact with the clays present and prevents native pore fluids escaping from the sample. Oil cannot intrude fully water saturated nanopores in shale at ambient pressures due to immiscibility and wettability issues. Other potential fluids that can be used for shale preservation include decane [e.g., Ewy et al., 2008; Ewy, 2014]. Core plugs subsampled from recovered core should also be sealed in glass vials immersed in an appropriate preservative solution. Should such materials not be available, a short‐term solution would be to coat cores or plugs in cling film, tin foil, and wax as a short‐period (weeks to months) stopgap and kept cool in a fridge (but not frozen). However, it would be preferable to immerse in the fluids suggested above as soon as possible as wax is slightly permeable to air and samples will eventually begin to desiccate.

In order to avoid sample desiccation and concomitant alteration of rock properties (see examples below), a workflow has been developed to maximize high‐quality results from preserved shale cores (Fig. 1.1). Initially, a whole core is X‐ray CT scanned in order to look for fractures, limestone stringers, nodules, and the like. This allows the development of a coring plan (Fig. 1.2) directly linked to the workflow which avoids such features and means that when core plugs are taken, exposure to air is minimized. While conventional rotary coring is sometimes used for harder and more isotropic shales, in general a Murg diamond wire bandsaw is used to take core plugs, and these plugs are finished off on a cylindrical grinder. This allows significantly increased core plug recovery and better quality of plugs taken in these notoriously difficult‐to‐prepare rocks. Shales are at their weakest in tension parallel to bedding [e.g., Fjær et al., 2008], and rotary core plugs often lead to biscuiting due to closely spaced fracture development parallel to the fabric anisotropy. The lack of stress induced by torque in the case of the diamond wire bandsaw means that plugs can be taken in more difficult rocks without imposing stresses on the intrinsic planes of weakness in the shale and better plug condition and recovery is the result.

Figure 1.1...