Hierarchical integration of porosity in shales

Abstract

Pore characterization in shales is challenging owing to the wide range of pore sizes and types present. Haynesville-Bossier shale (USA) was sampled as a typical clay-bearing siliceous, organic-rich, gas-mature shale and characterized over pore diameters ranging 2 nm to 3000 nm. Three advanced imaging techniques were utilized correlatively, including the application of Xe+ plasma focused ion beam scanning electron microscopy (plasma FIB or PFIB), complemented by the Ga+ FIB method which is now frequently used to characterise porosity and organic/inorganic phases, together with transmission electron microscope tomography of the nano-scale pores (voxel size 0.6 nm; resolution 1–2 nm). The three pore-size scales each contribute differently to the pore network. Those <10 nm (greatest number), 10 nm to 100 nm (best-connected hence controls transport properties), and >100 nm (greatest total volume hence determines fluid storativity). Four distinct pore types were found: intra-organic, organic-mineral interface, inter-mineral and intra-mineral pores were recognized, with characteristic geometries. The whole pore network comprises a globally-connected system between phyllosilicate mineral grains (diameter: 6–50 nm), and locally-clustered connected pores within porous organic matter (diameter: 200–800 nm). Integrated predictions of pore geometry, connectivity, and roles in controlling petrophysical properties were verified through experimental permeability measurements.

A Triple Pore Network Model (T-PNM) for Gas Flow Simulation in Fractured, Micro-porous and Meso-porous Media

“…In other words, when is 0 it means that we have no interconnected microporosity in the solid element and when it is 1, it means there is no isolated micro-porosity within the solid element. This parameter can be obtained from nano-tomography, highresolution FIB-SEM images (Ma et al 2018), or by density analysis of the crushed particles of the porous sample (Luffel and Guidry 1992). Here, we have simply assumed that is 0.95.…”

Mineral Precipitation in Fractures and Nanopores within Shale Imaged Using Time-Lapse X-ray Tomography

“…The sample was characterized as organic-rich (total organic content (TOC) 3.7 wt.%) and gas-mature (Ro 2.3%). The main minerals as quantified using X-ray diffraction (XRD) are quartz, calcite, ankerite, albite, pyrite, illite, chlorite, and muscovite [19]. The helium porosity of similar samples is 7.0% at ambient pressure, and the permeability ranges from 1.0 × 10 −17 to 3.7 × 10 −21 m 2 at a constant pore fluid pressure of 23 MPa when the effective pressure increases from 0 MPa to 70 MPa [19].…”

Best Practices for Shale Core Handling: Transportation, Sampling and Storage for Conduction of Analyses

“…As a result of the complex rock fabric of shale and their weak organic/inorganic contacts, they are prone to micro fracturing during coring and core retrieval. The porosity in shales manifests in different ways, such as intragranular pores, dissolution pores due to mineral alteration, interstitial pores between clay packages and micro fractures, and fissures in micas [20]. The presence of pores eventually dictates their stability and failure limit.…”