Matrix-related pore networks in mudrocks are composed of nanometer- to micrometer-size pores. In shale-gas systems, these pores, along with natural fractures, form the flow-path (permeability) network that allows flow of gas from the mudrock to induced fractures during production. A pore classification consisting of three major matrix-related pore types is presented that can be used to quantify matrix-related pores and relate them to pore networks. Two pore types are associated with the mineral matrix; the third pore type is associated with organic matter (OM). Fracture pores are not controlled by individual matrix particles and are not part of this classification. Pores associated with mineral particles can be subdivided into interparticle (interP) pores that are found between particles and crystals and intraparticle (intraP) pores that are located within particles. Organic-matter pores are intraP pores located within OM. Interparticle mineral pores have a higher probability of being part of an effective pore network than intraP mineral pores because they are more likely to be interconnected. Although they are intraP, OM pores are also likely to be part of an interconnected network because of the interconnectivity of OM particles. In unlithifed near-surface muds, pores consist of interP and intraP pores, and as the muds are buried, they compact and lithify. During the compaction process, a large number of interP and intraP pores are destroyed, especially in ductile grain-rich muds. Compaction can decrease the pore volume up to 88% by several kilometers of burial. At the onset of hydrocarbon thermal maturation, OM pores are created in kerogen. At depth, dissolution of chemically unstable particles can create additional moldic intraP pores.

Spectrum of pore types and networks in mudrocks and a descriptive classification for matrix-related mudrock pores

Responding to the latest developments in rock physics research, this popular reference book has been thoroughly updated while retaining its comprehensive coverage of the fundamental theory, concepts, and laboratory results. It brings together the vast literature from the field to address the relationships between geophysical observations and the underlying physical properties of Earth materials - including water, hydrocarbons, gases, minerals, rocks, ice, magma and methane hydrates. This third edition includes expanded coverage of topics such as effective medium models, viscoelasticity, attenuation, anisotropy, electrical-elastic cross relations, and highlights applications in unconventional reservoirs. Appendices have been enhanced with new materials and properties, while worked examples (supplemented by online datasets and MATLAB® codes) enable readers to implement the workflows and models in practice. This significantly revised edition will continue to be the go-to reference for students and researchers interested in rock physics, near-surface geophysics, seismology, and professionals in the oil and gas industries.

The Rock Physics Handbook

Many currently producing shale-gas reservoirs are overmature oil-prone source rocks. Through burial and heating these reservoirs evolve from organic-matter-rich mud deposited in marine, lacustrine, or swamp environments. Key characterization parameters are: total organic carbon (TOC), maturity level (vitrinite reflectance), mineralogy, thickness, and organic matter type. Hydrogento-carbon (HI) and oxygen-to-carbon (OI) ratios are used to classify organic matter that ranges from oil-prone algal and herbaceous to gas-prone woody/coaly material. Although organic-matter-rich intervals can be hundreds of meters thick, vertical variability in TOC is high ( 50% of the total porosity, and these pores may be hydrocarbon wet, at least during most of the thermal maturation process. A full understanding of the relation of porosity and gas content will result in development of optimized processes for hydrocarbon recovery in shale-gas reservoirs.

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From Oil-Prone Source Rock to Gas-Producing Shale Reservoir - Geologic and Petrophysical Characterization of Unconventional Shale Gas Reservoirs

https://www.searchanddiscovery.com/abstracts/pdf/2011/hedberg-texas/abstracts/ndx_zhang.pdf

Effect of organic-matter type and thermal maturity on methane adsorption in shale-gas systems

The Marcellus Formation of Pennsylvania represents an outstanding example of an organic matter (OM)–hosted pore system; most pores detectable by field-emission scanning electron microscopy (FE-SEM) are associated with OM instead of mineral matrix. In the two wells studied here, total organic carbon (TOC) content is a stronger control on OM-hosted porosity than is thermal maturity. The two study wells span a maturity from late wet gas (vitrinite reflectance [Ro], 1.0%) to dry gas (Ro, 2.1%). Samples with a TOC less than 5.5 wt. % display a positive correlation between TOC and porosity, but samples with a TOC greater than 5.5 wt. % display little or no increase in porosity with a further increasing TOC. In a subset of samples (14) across a range of TOC (2.3–13.6 wt. %), the pore volume detectable by FE-SEM is a small fraction of total porosity, ranging from 2 to 32% of the helium porosity. Importantly, the FE-SEM–visible porosity in OM decreases significantly with increasing TOC, diminishing from 30% of OM volume to less than 1% of OM volume across the range of TOC. The morphology and size of OM-hosted pores also vary systematically with TOC. The interpretation of this anticorrelation between OM content and SEM-visible pores remains uncertain. Samples with the lowest OM porosity (higher TOC) may represent gas expulsion (pore collapse) that was more complete as a consequence of greater OM connectivity and framework compaction, whereas samples with higher OM porosity (lower TOC) correspond to rigid mineral frameworks that inhibited compactional expulsion of methane-filled bubbles. Alternatively, higher TOC samples may contain OM (low initial hydrogen index, relatively unreactive) that is less prone to development of FE-SEM–detectable pores. In this interpretation, OM type, controlled by sequence-stratigraphic position, is a factor in determining pore-size distribution.

Organic matter–hosted pore system, Marcellus Formation (Devonian), Pennsylvania

Development of organic porosity in the Woodford Shale with increasing thermal maturity

The microstructure of gas shale samples from nine different formations has been investigated using a combination of focused ion beam (FIB) milling and scanning electron microscopy (SEM). Backscattered electron (BSE) images of FIB cross sectioned shale surfaces show a complex microstructure with variations observed among the formations. Energy dispersive spectroscopy of the shale cross sections indicates that clay, carbonate, quartz, pyrite, and kerogen are the most prevalent components. In the BSE images, areas of kerogen are observed interspersed with the inorganic grains. Pores are observed in both the kerogen and inorganic matrix with the size, shape, and number of pores varying among the shale samples. By using FIB milling and SEM imaging sequentially and repetitively, three-dimensional (3-D) data sets of SEM images have been generated for each of the shale samples. Three-dimensional volumes of the shales are reconstructed from these images. By setting thresholds on the gray scale, the kerogen and pore networks are segmented out and visualized in the reconstructed shale volumes. Estimates of kerogen and pore volume percentages of the reconstructed shale volumes have been made and range from 0 to 90.0% for the kerogen and 0.2 to 2.3% for pores. Estimates of pore-size distributions suggest that although pores with radii of approximately 3 nm dominate in number, they do not necessarily dominate in total volumetric contribution. Scanning electron microscopy images and 3-D reconstructions reinforce the facts that shales are quite different and that their microstructures are highly variable and complex.

Carl H. Sondergeld

Papers

Development of organic porosity in the Woodford Shale with increasing thermal maturity

Microstructural investigation of gas shales in two and three dimensions using nanometer-scale resolution imaging

Shale Gas-in-Place Calculations Part I: New Pore-Scale Considerations

Micro-Structural Studies of Gas Shales

Structural Characterization of Gas Shales on the Micro- and Nano-Scales