Stephen E. Laubach

Characteristics and origins of coal cleat: A review

Abstract Cleats are natural opening-mode fractures in coal beds. They account for most of the permeability and much of the porosity of coalbed gas reservoirs and can have a significant effect on the success of engineering procedures such as cavity stimulations. Because permeability and stimulation success are commonly limiting factors in gas well performance, knowledge of cleat characteristics and origins is essential for successful exploration and production. Although the coal–cleat literature spans at least 160 years, mining issues have been the principal focus, and quantitative data are almost exclusively limited to orientation and spacing information. Few data are available on apertures, heights, lengths, connectivity, and the relation of cleat formation to diagenesis, characteristics that are critical to permeability. Moreover, recent studies of cleat orientation patterns and fracture style suggest that new investigations of even these well-studied parameters can yield insight into coal permeability. More effective predictions of cleat patterns will come from advances in understanding cleat origins. Although cleat formation has been speculatively attributed to diagenetic and/or tectonic processes, a viable mechanical process for creating cleats has yet to be demonstrated. Progress in this area may come from recent developments in fracture mechanics and in coal geochemistry.

Natural fractures in shale: A review and new observations

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.

Practical approaches to identifying sealed and open fractures

For one essential ingredient of permeable fracture networks (degree of fracture pore-space preservation in large fractures), I show how the characterization challenge presented by sparse fracture sampling can be overcome by measuring a surrogate, the abundance of rock-mass cement that precipitated after fractures ceased opening. Sampling limitations are overcome because the surrogate is readily measured in small rock samples, including sidewall cores and cuttings, permitting site-specific diagnosis of the capacity of fractures to transmit fluid over a wider range of sample depths than conventional methods allow. A diverse core database shows that this surrogate correctly predicts where large fractures are sealed. Information on timing of fracture opening relative to cement sequence can be obtained in two ways. First, evidence of fracture-movement history and cement sequences in sparse large fractures can be extrapolated to areas having only cement data. Alternately, evidence of fracture timing can be acquired from sealed, micrometer-scale fractures. Distribution of porosity-reducing cement is commonly heterogeneous (from bed to bed and location to location) in siliciclastic and carbonate rocks. However, because patterns of sealed or open fractures cannot be delineated using fracture observations alone, surrogates have practical value for production fairway mapping and other applications in which identifying open fractures is essential. This study highlights the vital interplay among structural and diagenetic processes for fracture-porosity preservation or destruction.

A scale-independent approach to fracture intensity and average spacing measurement

Fracture intensity, the number of fractures per unit length along a sample line, is an important attribute of fracture systems that can be problematic to establish in the subsurface. Lack of adequate constraints on fracture intensity may limit the economic exploitation of fractured reservoirs because intensity describes the abundance of fractures potentially available for fluid flow and the probability of encountering fractures in a borehole. Traditional methods of fracture-intensity measurement are inadequate because they ignore the wide spectrum of fracture sizes found in many fracture systems and the consequent scale dependence of fracture intensity. An alternative approach makes use of fracture-size distributions, which allow more meaningful comparisons between different locations and allow microfractures in subsurface samples to be used for fracture-intensity measurement. Comparisons are more meaningful because sampling artifacts can be recognized and avoided, and because common thresholds of fracture size can be enforced for counting in different locations. Additionally, quantification of the fracture-size distribution provides a mechanism for evaluation of uncertainties. Estimates of fracture intensity using this approach for two carbonate beds in the Sierra Madre Oriental, Mexico, illustrate how size-cognizant measurements cast new light on widely accepted interpretation of geologic controls of fracture intensity.

Mechanical and fracture stratigraphy

Using examples from core studies, this article shows that separate identification of mechanical stratigraphy and fracture stratigraphy leads to a clearer understanding of fracture patterns and more accurate prediction of fracture attributes away from the wellbore. Mechanical stratigraphy subdivides stratified rock into discrete mechanical units defined by properties such as tensile strength, elastic stiffness, brittleness, and fracture mechanics properties. Fracture stratigraphy subdivides rock into fracture units according to extent, intensity, or some other observed fracture attribute. Mechanical stratigraphy is the by-product of depositional composition and structure, and chemical and mechanical changes superimposed on rock composition, texture, and interfaces after deposition. Fracture stratigraphy reflects a specific loading history and mechanical stratigraphy during failure. Because mechanical property changes reflect diagenesis and fractures evolve with loading history, mechanical stratigraphy and fracture stratigraphy need not coincide. In subsurface studies, current mechanical stratigraphy is generally measurable, but because of inherent limitations of sampling, fracture stratigraphy is commonly incompletely known. To accurately predict fractures in diagenetically and structurally complex settings, we need to use evidence of loading and mechanical property history as well as current mechanical states.

Natural fracture characterization in tight gas sandstones: Integrating mechanics and diagenesis

Accurate predictions of natural fracture flow attributes in sandstones require an understanding of the underlying mechanisms responsible for fracture growth and aperture preservation. Poroelastic stress calculations combined with fracture mechanics criteria show that it is possible to sustain opening-mode fracture growth with sublithostatic pore pressure without associated or preemptive shear failure. Crack-seal textures and fracture aperture to length ratios suggest that preserved fracture apertures reflect the loading state that caused propagation. This implies that, for quartz-rich sandstones, the synkinematic cement in the fractures and in the rock mass props fracture apertures open and reduces the possibility of aperture loss on unloading and relaxation. Fracture pattern development caused by subcritical fracture growth for a limited range of strain histories is demonstrated to result in widely disparate fracture pattern geometries. Substantial opening-mode growth can be generated by very small extensional strains (on the order of 104); consequently, fracture arrays are likely to form in the absence of larger scale structures. The effective permeabilities calculated for these low-strain fracture patterns are considerable. To replicate the lower permeabilities that typify tight gas sandstones requires the superimposition of systematic cement filling that preferentially plugs fracture tips and other narrower parts of the fracture pattern.

Natural fractures in shale

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.

A 48 m.y. history of fracture opening, temperature, and fluid pressure: Cretaceous Travis Peak Formation, East Texas basin

Quartz cement bridges across opening-mode fractures of the Cretaceous Travis Peak Formation provide a textural and fluid inclusion record of incremental fracture opening during the burial evolution of this low-porosity sandstone. Incremental crack-seal fracture opening is inferred based on the banded structure of quartz cement bridges, consisting of up to 700 cement bands averaging ∼5 μm in thickness as observed with scanning electron microscope–cathodoluminescence. Crack-seal layers contain assemblages of aqueous two-phase fluid inclusions. Based on fluid inclusion microthermometry and Raman microprobe analyses, we determined that these inclusions contain methane-saturated brine trapped over temperatures ranging from ∼130°C to ∼154°C. Using textural crosscutting relations of quartz growth increments to infer the sequence of cement growth, we reconstructed the fluid temperature and pore-fluid pressure evolution during fracture opening. In combination with published burial evolution models, this reconstruction indicates that fracture opening started at ca. 48 Ma and above-hydrostatic pore-fluid pressure conditions, and continued under steadily declining pore-fluid pressure during partial exhumation until present times. Individual fractures opened over an ∼48 m.y. time span at rates of 16–23 μm/m.y. These rates suggest that fractures can remain hydraulically active over geologically long times in deep basinal settings.

Subsurface fractures and their relationship to stress history in East Texas basin sandstone

Abstract Subsurface fractures were sampled with more than 400 m of core from the Lower Cretaceous Travis Peak Formation, a tabular sandstone and shale unit approximately 600 m thick that was deposited in the gradually subsiding Gulf Coast basin. Depth to the top of the formation in East Texas now ranges between 1800 and 2900 m. Fractures in sandstone exhibit features that are due to intermittent fracturing and sealing (“crack-seal”), which suggest that the fractures are the result of episodes of fluid pressure in excess of hydrostatic. Correlation of the vein-mineral precipitation sequence with the diagenetic history and the results of previous δ 18 O studies of quartz cement, indicates that fractures propagated at depths of between 900 and 1500 m during the migration of quartz-precipitating fluids. Fracture permeability provides a mechanism for the passage of large fluid volumes recorded by the precipitation of extensive quartz cement in the formation. Fractures stopped propagating before maximum burial depth was achieved. During approximately 1500 m of subsequent burial, fractures either remained partly open or were sealed by postkinematic ankerite and clay minerals.

A Method to Detect Natural Fracture Strike in Sandstones

In siliciclastic hydrocarbon reservoir rocks, economic gas and oil production may depend on the attributes of natural fractures, and, with the advent of horizontal drilling, fractures are increasingly exploration and development targets; yet reliable information on such key fracture attributes as orientation (strike) is sparse because few fractures intersect vertical well bores. This paper describes how fracture strike can be documented on a bed-by-bed basis even in well bores where few or no visible fractures are directly sampled. Quartz-lined opening-mode microfractures (lengths of microns to millimeters) in quartz-cemented sandstones commonly are not visible using standard petrographic methods, but systematic mapping of these microfractures is possible using photomultiplier-based electron beam-induced luminescence (scanned cathodoluminescence) imaging. As shown by observations, primarily from three natural gas plays and one oil play in the United States, microfracture strike is a good guide to the strike of large fractures (macrofractures) that formed concurrently. Because microfractures are widespread and small specimens can be used to get accurate fracture-strike data, this approach can be applied to samples obtained from wireline-conveyed rotary (drilled) sidewall coring devices, as well as to samples from full-diameter core.