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

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

The identification of organoporosity (microscale and nanoscale pores within organic matter in shales), its importance to storage and perhaps transfer of gas molecules through shales, and methods for gathering three-dimensional images of the pores, such as by argon-ion milling and/or field emission scanning electron microscopy, have all been well documented and discussed for unconventional gas shales. However, other types of pores exist within shales that can be important to storage and migration of gas (and oil), and other technologies are available for their identification and imaging. The different pore types found in the Barnett and Woodford shales are described and classified in this article. Scanning electron microscopy revealed the presence of porous floccules in both the Barnett and Woodford shales, which appear similar to laboratory-produced floccules and to those in other ancient shales. Published experimental and observational studies indicate that floccules are hydraulically equivalent to coarser grains and are transported by traction processes. Current-induced microsedimentary structures and textures within the Barnett and Woodford shales, as well as the preserved floccules, suggest such processes were active during transport and deposition. Pore spaces between the floccules are open and can provide storage space as well as permeability pathways for gas molecules through the shales. Pores are also found within organic matter that occurs both as discrete particles and as adsorbed coatings around clay grains in the shale. They are referred to here as “organopores.” Porous fecal pellets are also common in the Barnett Shale. Preserved fossil fragments such as organic-walled spores and inorganic sponge spicules have hollow central chambers, which may remain partially or completely open even after burial. Intraparticle pores occur between grains of various minerals (e.g., pyrite framboids). Microchannels within shale matrix, which may be the bounding surfaces of scours or microsedimentary structures, may also provide permeability pathways for hydrocarbon migration. Mircrofractures are also common, and their initiation might be related to mineral crystal structure. When present in sufficient quantity, these pore types offer potential gas (and oil) molecule storage spaces and permeability pathways through the shales.

Pore types in the Barnett and Woodford gas shales: Contribution to understanding gas storage and migration pathways in fine-grained rocks

Natural fractures have long been suspected as a factor in production from shale reservoirs because gas and oil production commonly exceeds the rates expected from low-porosity and low-permeability shale host rock. Many shale outcrops, cores, and image logs contain fractures or fracture traces, and microseismic event patterns associated with hydraulic-fracture stimulation have been ascribed to natural fracture reactivation. Here we review previous work, and present new core and outcrop data from 18 shale plays that reveal common types of shale fractures and their mineralization, orientation, and size patterns. A wide range of shales have a common suite of types and configurations of fractures: those at high angle to bedding, faults, bed-parallel fractures, early compacted fractures, and fractures associated with concretions. These fractures differ markedly in their prevalence and arrangement within each shale play, however, constituting different fracture stratigraphies—differences that depend on interface and mechanical properties governed by depositional, diagenetic, and structural setting. Several mechanisms may act independently or in combination to cause fracture growth, including differential compaction, local and regional stress changes associated with tectonic events, strain accommodation around large structures, catagenesis, and uplift. Fracture systems in shales are heterogeneous; they can enhance or detract from producibility, augment or reduce rock strength and the propensity to interact with hydraulic-fracture stimulation. Burial history and fracture diagenesis influence fracture attributes and may provide more information for fracture prediction than is commonly appreciated. The role of microfractures in production from shale is currently poorly understood yet potentially critical; we identify a need for further work in this field and on the role of natural fractures generally.

Natural fractures in shale: A review and new observations

Field observations show that hydraulic fracture growth in naturally fractured formations like shale is complex. Preexisting discontinuities in shale, including natural fractures and bedding, act as planes of weakness that divert fracture propagation. To investigate the influence of weak planes on hydraulic fracture propagation, we performed Semicircular Bend tests on Marcellus Shale core samples containing calcite-filled natural fractures (veins). The approach angle of the induced fracture to the veins and the thickness of the veins have a strong influence on propagation. As the approach angle becomes more oblique to the induced fracture plane, and as the vein gets thicker, the induced fracture is more likely to divert into the vein. Microstructural analysis of tested samples shows that the induced fracture propagates in the middle of the vein but not at the interface between the vein and the rock matrix. Cleavage planes and fluid inclusion trails in the vein cements exert some control on the fracture path. Combining the experimental results with theoretical fracture mechanics arguments, the fracture toughness of the calcite veins was estimated to range from 0.24 MPa m1/2 to 0.83 MPa m1/2, depending on the value used for the Young's modulus of the calcite vein material. Measured fracture toughness of unfractured Marcellus Shale was 0.47 MPa m1/2.

https://agupubs.onlinelibrary.wiley.com/doi/pdf/10.1002/2014JB011358

The interaction of propagating opening mode fractures with preexisting discontinuities in shale

Modeling Coupled Fracture-Matrix Fluid Flow in Geomechanically Simulated Fracture Networks

Examining Hydraulic Fracture - Natural Fracture Interaction in Hydrostone Block Experiments

/pdf/examining-the-effect-of-cemented-natural-fractures-on-1h5f0536de.pdf

Jon Holder

Papers

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

The interaction of propagating opening mode fractures with preexisting discontinuities in shale

Modeling Coupled Fracture-Matrix Fluid Flow in Geomechanically Simulated Fracture Networks

Examining Hydraulic Fracture - Natural Fracture Interaction in Hydrostone Block Experiments

Examining the Effect of Cemented Natural Fractures on Hydraulic Fracture Propagation in Hydrostone Block Experiments