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

Investigation of pore networks in mudrocks is important because shale gas has become a major exploration target and understanding pore networks of these very fine grained rocks is essential to an understanding of production rates and reserves. However, identifying and characterizing mudrock pores are difficult because of their nanometer to micron scale. With development of argon-milling surface-preparation techniques and use of field-emission scanning-electron microscopes, we can now image pores as small as 5 nanometers (nm). A number of different pore types have been identified, and combinations of pore types that constitute pore networks in different mudrock suites are variable. Basic pore types are divided into those associated with organic matter and those that are not. Pores within organic matter appear to be related to thermal maturation of organic matter. Nonorganic-matter pores can be divided into interparticle and intraparticle types and are strongly affected by mechanical and chemical diagenesis. Interparticle pores occur between grains and crystals, whereas intraparticle pores are found within the boundaries of grains. The latter include dissolution molds in fossils and particles, intercrystalline pores within framboids of pyrite, fluid inclusions in crystals, and pores within phosphate grains. Pore types vary in variety and abundance within differing shale-gas reservoir systems. Mississippian Barnett mudrock pores are dominantly associated with organic matter, Jurassic Haynesville/Bossier mudrocks contain mostly interparticle pores, and Cretaceous Pearsall mudrocks contain primarily intraparticle pores. Mudrock pore networks can be overprinted by fractures, producing a dual pore system.

Preliminary Classification of Matrix Pores in Mudrocks

Multiple causes of diagenetic fabric anisotropy in weakly consolidated mud, Nankai accretionary prism, IODP Expedition 316

Abstract Fracture geometries and fracture-sealing characteristics in dolostones reflect interactions among mechanical and chemical processes integrated over geological timescales. The mechanics of subcritical fracture growth results in fracture sets having power-law size distributions where the attributes of large, open fractures that affect reservoir flow behaviour can be accurately inferred from observations of cement-sealed microfractures and other microscopic diagenetic features, which are widespread in dolostones. Fracture porosity is governed by the competing rates of fracture opening and cement precipitation during fracture growth and by cements that post-date fracture opening. Combined analysis of structural and diagenetic features provides the best approach for understanding how fracture systems influence fluid flow. We review previous work and integrate new data on fractures and diagenetic features in cores from the Lower Ordovician Ellenburger and Permian Clear Fork formations in West Texas, and the Lower Ordovician Knox Group in Mississippi, together with outcrop samples of Lower Cretaceous Cupido Formation dolostones from the Sierra Madre Oriental, Mexico, in order to illustrate our approach.

Predicting and characterizing fractures in dolostone reservoirs: using the link between diagenesis and fracturing

At Cranfield field, Mississippi, a monitored carbon dioxide (CO2) sequestration and enhanced oil recovery project provides a unique opportunity to study sealing properties of a marine shale as a CO2-confining zone. The reservoir is in the amalgamated fluvial basal sandstone of the lower Tuscaloosa Formation at depths of more than 3000 m (9843 ft). The marine mudstone of the middle Tuscaloosa forms a continuous regional confining system of approximately 75 m (246 ft).A 6-m (20-ft) core was retrieved from the middle Tuscaloosa marine mudstone approximately 70 m (230 ft) above the CO2 injection zone. We conducted a series of characterizing analyses on the core that would enable us to assess with high confidence seal performance over geologic time. The core displays considerable heterogeneity at centimeter to decimeter scales, with lithology varying from silt-bearing clay-rich mudstone to siltstone and very fine grained sandstone. In total, nine microfacies are recognized in the core. Petrographic, mineralogical, and chemical analyses (scanning electron microscopy, x-ray diffraction, and x-ray fluorescence) show that calcite cements preferentially form in coarser grained beds and have greatly reduced porosity and permeability, making silty and sandy beds less permeable than mudstone. Mercury intrusion capillary pressure tests show desirable sealing capacity for all samples capable of retaining a CO2 column of 49 to 237 m (161–778 ft) at 100% water saturation. Permeability and porosity of all facies are less than 0.0001 md and 4%, respectively. Pores in the samples are at nanometer scales, with modal pore-throat sizes less than 20 nm. Scanning electron microscopic imaging on ion-milled surfaces confirms that nanopores are scarce and generally isolated.

Robert M. Reed

Papers

Preliminary Classification of Matrix Pores in Mudrocks

Multiple causes of diagenetic fabric anisotropy in weakly consolidated mud, Nankai accretionary prism, IODP Expedition 316

Predicting and characterizing fractures in dolostone reservoirs: using the link between diagenesis and fracturing

Diagenesis and sealing capacity of the middle Tuscaloosa mudstone at the Cranfield carbon dioxide injection site, Mississippi, U.S.A.

Comment on “Formation of nanoporous pyrobitumen residues during maturation of the Barnett Shale (Fort Worth Basin)” by Bernard et al. (2012)