Shale-gas resource plays can be distinguished by gas type and system characteristics. The Newark East gas field, located in the Fort Worth Basin, Texas, is defined by thermogenic gas production from low-porosity and low-permeability Barnett Shale. The Barnett Shale gas system, a self-contained source-reservoir system, has generated large amounts of gas in the key productive areas because of various characteristics and processes, including (1) excellent original organic richness and generation potential; (2) primary and secondary cracking of kerogen and retained oil, respectively; (3) retention of oil for cracking to gas by adsorption; (4) porosity resulting from organic matter decomposition; and (5) brittle mineralogical composition. The calculated total gas in place (GIP) based on estimated ultimate recovery that is based on production profiles and operator estimates is about 204 bcf/section (5.78 × 10 9 m 3 /1.73 × 10 4 m 3 ). We estimate that the Barnett Shale has a total generation potential of about 609 bbl of oil equivalent/ac-ft or the equivalent of 3657 mcf/ac-ft (84.0 m 3 /m 3 ). Assuming a thickness of 350 ft (107 m) and only sufficient hydrogen for partial cracking of retained oil to gas, a total generation potential of 820 bcf/section is estimated. Of this potential, approximately 60% was expelled, and the balance was retained for secondary cracking of oil to gas, if sufficient thermal maturity was reached. Gas storage capacity of the Barnett Shale at typical reservoir pressure, volume, and temperature conditions and 6% porosity shows a maximum storage capacity of 540 mcf/ac-ft or 159 scf/ton.

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Unconventional shale-gas systems: The Mississippian Barnett Shale of north-central Texas as one model for thermogenic shale-gas assessment

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

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The Biomarker Guide

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

Acid mine drainage remediation options: a review

We present an interpretational framework for the analysis of a diverse set of geological structures that breach sealing sequences and allow fluids to flow vertically or subvertically across the seal. In so doing, they act as seal bypass systems (SBS). We define SBS as seismically resolvable geological features embedded within sealing sequences that promote cross-stratal fluid migration and allow fluids to bypass the pore network. If such bypass systems exist within a given seal sequence, then predictions of sealing capacity based exclusively on the flow properties (capillary entry pressure and hydraulic conductivity) of the bulk rock can potentially be negated by the capacity of the bypass system to breach the grain and pore network. We present a range of examples of SBS affecting contrasting types of sealing sequences using three-dimensional (3-D) seismic data. These examples show direct evidence of highly focused vertical or subvertical fluid flow from subsurface reservoirs up through the seal sequence, with leakage internally at higher levels or to the surface as seeps.We classify SBS into three main groups based on seismic interpretational criteria: (1) fault related, (2) intrusion related, and (3) pipe related. We show how each group exhibits different modes of behavior with different scaling relationships between flux and dimensions and different short- and long-term impacts on seal behavior.

Seal bypass systems

Mudstone is the most abundant sedimentary rock and variously acts as sources, seals, and shale gas reservoirs in petroleum systems. Many important physicochemical properties of mudstones are strongly influenced by the mineralogy and size of deposited grains, and by diagenetic changes (precompaction and postcompaction); these are commonly predictable. The diverse composition of mudstones reflects input and hydrodynamic segregation of detrital materials to basins, primary production within basins, and diagenetic processes (both precipitation and dissolution) in the sediment. High-magnification observations both in modern and ancient sediments demonstrate that mudstones are texturally and mineralogically heterogeneous; this variability is not always readily apparent. Although some mud is indeed deposited by suspension settling out of low-energy buoyant plumes, textural analyses reveal that it is commonly dispersed by a combination of waves, gravity-driven processes, and unidirectional currents driven variously by storms and tides. Such dispersal mechanisms mean that muddy successions are typically organized into packages that can be interpreted using sequence stratigraphy. Early bioturbation homogenizes mud, whereas early chemical diagenesis can result in highly cemented zones developing, especially at stratal surfaces. The nature of deeper burial diagenesis, which involves compaction, mineral dissolution, recrystallization, mineral reorientation and lithification, and petroleum generation, is preconditioned by depositional and early diagenetic characteristics of the mud. Although the petrophysical properties of homogeneous mudstones are reasonably well known, the quantitative implications of heterogeneity for petroleum expulsion, retention, petroleum migration, seal capacity, acoustic anisotropy, and identification of shale gas reservoir sweet spots are essentially unexplored. Future work should seek to redress this position.

Mudstone diversity: Origin and implications for source, seal, and reservoir properties in petroleum systems

Shale gas is becoming an increasingly important energy resource. In this study, the adsorption of methane on a dry, organic-rich Alum shale sample was studied at pressures up to ∼14 MPa and temperatures in the range 300–473 K, which are relevant to gas storage under geological conditions. Maximum methane excess uptake was 0.176–0.042 mmol g–1 (125–30 scf t–1) for the temperature range of 300–473 K. The decrease in maximum methane surface excess with increasing temperature can be described with a linear model. An isosteric enthalpy of adsorption 19.2 ± 0.1 kJ mol–1 was determined at 0.025 mmol g–1 using the van’t Hoff equation. Supercritical adsorption was modeled using the modified Dubinin–Radushkevich and the Langmuir equations. The results are compared with absolute isotherms calculated from surface excess and the pore volumes obtained from subcritical gas adsorption (nitrogen (78 K), carbon dioxide (273 and 195 K), and CH4 (112 K)). The subcritical adsorption and the surface excess results allow an upp...

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Methane Adsorption on Shale under Simulated Geological Temperature and Pressure Conditions

The controls on the composition of biodegraded oils in the deep subsurface - part 1: biodegradation rates in petroleum reservoirs

Sorption capacities and pore characteristics of bulk shales and isolated kerogens have been determined for immature, oil-window, and gas-window mature samples from the Lower Toarcian Posidonia shale formation. Dubinin–Radushkevich (DR) micropore volumes, sorption pore volumes, and surface areas of shales and kerogens were determined from CO2 adsorption isotherms at −78 and 0 °C, and from N2 adsorption isotherms at −196 °C. Mercury injection capillary pressure porosimetry, grain density measurements, and helium pycnometry were used to determine shale and kerogen densities and total pore volumes. Total porosities decrease through the oil-window and then increase into the gas-window. High-pressure methane isotherms up to 14 MPa were determined at 45, 65, and 85 °C on dry shale and at 45 and 65 °C on kerogen. Methane excess uptakes at 65 °C and 11.5 MPa were in the range 0.056–0.110 mmol g–1 (40–78 scf t–1) for dry Posidonia shales and 0.36–0.70 mmol g–1 (253–499 scf t–1) for the corresponding dry kerogens. A...

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Andrew C. Aplin

Papers

Seal bypass systems

Mudstone diversity: Origin and implications for source, seal, and reservoir properties in petroleum systems

Methane Adsorption on Shale under Simulated Geological Temperature and Pressure Conditions

The controls on the composition of biodegraded oils in the deep subsurface - part 1: biodegradation rates in petroleum reservoirs

High-pressure methane adsorption and characterization of pores in Posidonia shales and isolated kerogens.