Research on mudrock attributes has increased dramatically since shale-gas systems have become commercial hydrocarbon production targets. One of the most significant research questions now being asked focuses on the nature of the pore system in these mudrocks. Our work on siliceous mudstones from the Mississippian Barnett Shale of the Fort Worth Basin, Texas, shows that the pores in these rocks are dominantly nanometer in scale (nanopores). We used scanning electron microscopy to characterize Barnett pores from a number of cores and have imaged pores as small as 5 nm. Key to our success in imaging these nanopores is the use of Ar-ion-beam milling; this methodology provides flat surfaces that lack topography related to differential hardness and are fundamental for high-magnification imaging.

Nanopores are observed in three main modes of occurrence. Most pores are found in grains of organic matter as intraparticle pores; many of these grains contain hundreds of pores. Intraparticle organic nanopores most commonly have irregular, bubblelike, elliptical cross sections and range between 5 and 750 nm with the median nanopore size for all grains being approximately 100 nm. Internal porosities of up to 20.2% have been measured for whole grains of organic matter based on point-count data from scanning electron microscopy analysis. These nanopores in the organic matter are the predominant pore type in the Barnett mudstones and they are related to thermal maturation.

Nanopores are also found in bedding-parallel, wispy, organic-rich laminae as intraparticle pores in organic grains and as interparticle pores between organic matter, but this mode is not common. Although less abundant, nanopores are also locally present in fine-grained matrix areas unassociated with organic matter and as nano- to microintercrystalline pores in pyrite framboids.

Intraparticle organic nanopores and pyrite-framboid intercrystalline pores contribute to gas storage in Barnett mudstones. We postulate that permeability pathways within the Barnett mudstones are along bedding-parallel layers of organic matter or a mesh network of organic matter flakes because this material contains the most pores.

Morphology, Genesis, and Distribution of Nanometer-Scale Pores in Siliceous Mudstones of the Mississippian Barnett Shale

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

The nanometer-scaled pore systems of gas shale reservoirs were investigated from the Barnett, Marcellus, Woodford, and Haynesville gas shales in the United States and the Doig Formation of northeastern British Columbia, Canada. The purpose of this article is to provide awareness of the nature and variability in pore structures within gas shales and not to provide a representative evaluation on the previously mentioned North American reservoirs. To understand the pore system of these rocks, the total porosity, pore-size distribution, surface area, organic geochemistry, mineralogy, and image analyses by electron microscopy were performed. Total porosity from helium pycnometry ranges between 2.5 and 6.6%. Total organic carbon content ranges between 0.7 and 6.8 wt. %, and vitrinite reflectance measured between 1.45 and 2.37%. The gas shales in the United States are clay and quartz rich, with the Doig Formation samples being quartz and carbonate rich and clay poor. Higher porosity samples have higher values because of a greater abundance of mesopores compared with lower porosity samples. With decreasing total porosity, micropore volumes relatively increase whereas the sum of mesopores and macropore volumes decrease. Focused ion beam milling, field emission scanning electron microscopy, and transmission electron microscopy provide high-resolution (∼5 nm) images of pore distribution and geometries. Image analysis provides a visual appreciation of pore systems in gas shale reservoirs but is not a statistically valid method to evaluate gas shale reservoirs. Macropores and mesopores are observed as either intergranular porosity or are confined to kerogen-rich aggregates and show no preferred orientation or align parallel with the laminae of the shale. Networks of mesopores are observed to connect with the larger macropores within the kerogen-rich aggregates.

Characterization of gas shale pore systems by porosimetry, pycnometry, surface area, and field emission scanning electron microscopy/transmission electron microscopy image analyses: Examples from the Barnett, Woodford, Haynesville, Marcellus, and Doig units

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

Gas production from the Barnett Shale relies on hydraulic fracture stimulation. Natural opening-mode fractures reactivate during stimulation and enhance efficiency by widening the treatment zone. Knowledge of both the present-day maximum horizontal stress, which controls the direction of hydraulic fracture propagation, and the geometry of the natural fracture system, which we discuss here, is therefore necessary for effective hydraulic fracture treatment design. We characterized natural fractures in four Barnett Shale cores in terms of orientation, size, and sealing properties. We measured a mechanical rock property, the subcritical crack index, which governs fracture pattern development. Natural fractures are common, narrow (0.05 mm; 0.002 in.), sealed with calcite, and present in en echelon arrays. Individual fractures have high length/width aspect ratios (1000:1). They are steep (75), and the dominant trend is west-northwest. Other sets trend north-south. The narrow fractures are sealed and cannot contribute to reservoir storage or enhance permeability, but the population may follow a power-law size distribution where the largest fractures are open. The subcritical crack index for the Barnett Shale is high, indicating fracture clustering, and we suggest that large open fractures exist in clusters spaced several hundred feet apart. These fracture clusters may enhance permeability locally, but they may be problematic for hydraulic fracture treatments. The smaller sealed fractures act as planes of weakness and reactivate during hydraulic fracture treatments. Because the maximum horizontal stress trends northeast-southwest and is nearly normal to the dominant natural fractures, reactivation widens the treatment zone along multiple strands.

Natural fractures in the Barnett Shale and their importance for hydraulic fracture treatments

Pore Networks and Fluid Flow in Gas Shales

Porosity, permeability, and total organic carbon (TOC) in a heterogeneous suite of 21 high-maturity samples (vitrinite reflectance 1.52–2.15%) from the Barnett Shale in the eastern Fort Worth Basin display few correlations with parameters of rock texture, fabric, and composition, these factors being mostly obscured by the effects of a protracted history of diagenesis. Diagenesis in these rocks includes mechanical and chemical modifications that occurred across a wide range of burial conditions. Compaction and cementation have mostly destroyed primary intergranular porosity. The porosity (average 5 vol. % by Gas Research Institute helium porosimetry) and pore size (8 nm median pore-throat diameter) are reduced to a degree such that pores are difficult to detect even by imaging Ar ion–milled surfaces with a field-emission scanning electron microscope. The existing porosity that can be imaged is mostly secondary and is localized dominantly within organic particulate debris and solid bitumen. The grain assemblage is highly modified by replacement. A weak pattern of correlation survives between bulk rock properties and the ratio of extrabasinal to intrabasinal sources of siliciclastic debris. Higher porosity, permeability, and TOC are observed in samples representing the extreme end members of mixing between extrabasinal siliciclastic sediment and intrabasinal-derived biosiliceous debris. Reservoir quality in these rocks is neither more strongly nor more simply related to variations in primary texture and composition because the interrelationships between texture and composition are complex and, importantly, the diagenetic overprint is too strong.

Robert M. Reed

Papers

Morphology, Genesis, and Distribution of Nanometer-Scale Pores in Siliceous Mudstones of the Mississippian Barnett Shale

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

Natural fractures in the Barnett Shale and their importance for hydraulic fracture treatments

Pore Networks and Fluid Flow in Gas Shales

Grain assemblages and strong diagenetic overprinting in siliceous mudrocks, Barnett Shale (Mississippian), Fort Worth Basin, Texas