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

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

Pendant drop tensiometry offers a simple and elegant solution to determining surface and interfacial tension - a central parameter in many colloidal systems including emulsions, foams and wetting phenomena. The technique involves the acquisition of a silhouette of an axisymmetric fluid droplet, and iterative fitting of the Young-Laplace equation that balances gravitational deformation of the drop with the restorative interfacial tension. Since the advent of high-quality digital cameras and desktop computers, this process has been automated with high speed and precision. However, despite its beguiling simplicity, there are complications and limitations that accompany pendant drop tensiometry connected with both Bond number (the balance between interfacial tension and gravitational forces) and drop volume. Here, we discuss the process involved with going from a captured experimental image to a fitted interfacial tension value, highlighting pertinent features and limitations along the way. We introduce a new parameter, the Worthington number, Wo, to characterise the measurement precision. A fully functional, open-source acquisition and fitting software is provided to enable the reader to test and develop the technique further.

Measurement of surface and interfacial tension using pendant drop tensiometry

: One use of spectral analysis of time series is to determine if two different time series are realizations from the same process This thesis develops the theory behind Krishnaiah and Schuurmann's theoretical work reported in their report Approximations to the Distributions of the Traces of Complex Multivariate Beta and F Matrices We take the trace of a test statistic calculated from the spectral density matrices of the time series and test it The thesis applies the theory to two small sample simulations (Author)

Spectral Analysis of Time Series.

Chapter 1. Petrophysical Rock Properties Chapter 2. Rock-fabric, Petrophysical Parameters, and Classification Chapter 3. Rock Fabric From Core Description and Wireline Logs Chapter 4. Spatial Distribution of Petrophysical Properties: Origin and Distribution of Depositional Textures Chapter 5. Spatial distribution of Petrophysical Properties: Diagenetic Overprinting and Rock Fabric Distribution Chapter 6. Reservoir Models for Input into Flow Simulators

Carbonate Reservoir Characterization

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

Determination de la tension interfaciale entre deux liquides par la methode de la goutte pendante et de la goutte sessile

James W. Jennings

Papers

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

An efficient method for the determination of interfacial tensions from drop profiles

Predicting Permeability From Well Logs in Carbonates With a Link to Geology for Interwell Permeability Mapping

Geostatistical Analysis of Permeability Data and Modeling of Fluid-Flow Effects in Carbonate Outcrops

Geostatistical analysis of petrophysical data and modeling of fluid-flow effects in carbonate outcrops