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

A review of immiscible fluids in the subsurface: properties, models, characterization and remediation

This paper discusses the migration of petroleum from its formation in a source rock to its subsequent possible entrapment in a reservoir. The chemical and physical properties of petroleum gases and liquids are stressed, particularly their phase behaviour under subsurface conditions which is shown to be a very important factor in determining migration behaviour. Engineering correlations are presented for estimating the properties of petroleum fluids under geologically realistic conditions. The directions and magnitudes of the forces acting on migrating petroleum are deduced from the combined effects of buoyancy and water flow in compacting sediments. These forces are combined, using a fluid potential description. This procedure allows the direction of migration to be denned. The rate of migration is then estimated from the properties of the sediments involved, allowing a distinction to be made between ‘lateral’ and ‘vertical’ carrier beds. This simplified approach is suitable for rapid predictive calculations in petroleum exploration. It is compared with the more complex 3-D computer modelling approaches which are currently becoming available. Migration losses are related to the cumulative pore volume employed by the petroleum in establishing a migration pathway. The petroleum migration mechanism is shown to be predominantly by bulk flow, with a small diffusive contribution for light hydrocarbons over distances less than c. 100 m. The loss factors involved in secondary migration are estimated from field evidence. The mechanism of reservoir filling is presented as a logical extension to those described for migration. This, together with the inefficiency of in-reservoir mixing by diffusion or convection, is shown to tend to cause significant lateral compostional gradients in reservoirs over and above the gravitationally induced vertical gradients described by other workers.

The movement and entrapment of petroleum fluids in the subsurface

Pore aperture size estimated from mercury injection tests has been used to evaluate seals for traps and to explain the locations of stratigraphic hydrocarbon accumulations. However, mercury injection tests are expensive and therefore not abundant. This paper develops empirical equations for estimating certain pore aperture size parameters from routine core analysis. The relationship of porosity, uncorrected air permeability, and various parameters derived from mercury injection-capillary pressure curves was established using multiple regression on a database of 202 samples of sandstone from 14 formations that range in age from Ordovician to Tertiary. These sandstone formations vary in composition and texture. A series of empirically derived equations also permits the calculation of pore aperture radii corresponding to mercury saturation values that range from 10 to 75% in increments of five. This makes it possible to construct a calculated pore aperture radius distribution curve using porosity and permeability from core analysis.

Relationship of porosity and permeability to various parameters derived from mercury injection-capillary pressure curves for sandstone

Fault zone permeability in outcrop is quantified by detailed geologic mapping and by measurements using a minipermeameter. Deformation bands, zones of deformation bands, and slip planes are structural elements associated with successive stages in the evolution of a fault zone in porous sandstones. Deformation bands have a porosity about one order of magnitude less than the surrounding host rock and, on average, a permeability three orders of magnitude less than the surrounding host rock. The intensity of cataclasis and the clay content control the amount of permeability reduction as measured perpendicular to a band. The wall rock in proximity to slip planes can have permeabilities more than seven orders of magnitude less than the pristine sandstone. Capillary pressure wit in deformation bands is estimated to be 10-100 times larger than that in the surrounding host rock. Thus, deformation bands and slip planes can substantially modify fluid flow properties of a reservoir and have potential sealing capabilities with respect to a nonwetting phase, as evident in outcrop exposure.

Effect of Faulting on Fluid Flow in Porous Sandstones: Petrophysical Properties

Capillary pressures between oil and water in rock pores are responsible for trapping oil, and the height of oil column, zo, in a reservoir may be calculated from the Hobson equation modified as follows: [EQUATION] where ^ggr is the interfacial tension between oil and water, rt is the radius of pore throats in the barrier rock, rp is the radius of pores in the reservoir rock, g is acceleration of gravity, and ^rgrw and ^rgro are the densities of water and oil, respectively, under subsurface conditions. To apply the equation, pore sizes must be estimated from mean effective grain sizes of the reservoir and barrier rocks. Effective grain size, De, in centimeters can be approximated from core analysis data by means of an empirical permeability equation from which [EQUATION] where n is porosity in percent and k is permeability in milli-darcys. Then pore and throat sizes may be estimated as functions of mean effective grain size as based on theoretical packings of grains. The oil-column equation assumes hydrostatic conditions, and additional column, ^Dgrzo, may be trapped if hydrodynamic flow occurs down the dip from barrier to reservoir facies, or [EQUATION] where dh/dx is the potentiometric gradient and xo is the width of the oil accumulation. Calculations of oil columns in stratigraphic fields show that the equations give values which are in fair to good agreement with observed oil columns; that porous and permeable, very fine-grained sandstones and siltstones are commonly effective barriers to oil migration; and that the recognition of such barriers can be important in exploration for stratigraphic traps.

Capillary Pressures in Stratigraphic Traps

Fracturing of low-permeability source rocks is induced by pore-pressure changes caused by the conversion of organic matter to less dense fluids (oil and gas); these fractures increase the permeability and provide pathways for hydrocarbon migration. An equation for the pressure change is derived using four major assumptions. (1) The permeability of the source rock is negligibly small (0.01 µd; 10-20 m2) so that the pore-pressure buildup by the conversion is much faster than its dissipation by pore-fluid flow. (2) The stress state is isotropic so that horizontal and vertical stresses are equal. The source rock fails when the pore pressure equals the overburden pressure. (3) The properties of the rock, organic matter, and fluids remain constant during oil generation. This assumption is valid when the change in depth (i.e., pressure and temperature) is small. (4) Only two reaction rates are required for the conversions, a low-temperature reaction rate for the kerogen/oil conversion (E approx. = 24 kcal/mol, A approx. = 1014/m.y.) and a high-temperature reaction rate for oil/gas conversion (E approx. = 52 kcal/mol, A approx. = 5.5 ´ 1026/m.y.). The equations for generation rate and pressure change are applied to the Austin source rock by adjusting the several variables to fit geochemical data, core saturations, and observed levels of oil and gas production. This application demonstrates that the equations are easily applied in calculating depths of primary migration for low-permeability source rocks.

Primary Migration by Oil-Generation Microfracturing in Low-Permeability Source Rocks: Application to the Austin Chalk, Texas

The principal mountain ranges of the Wyoming and Colorado foreland were raised asymmetrically by Laramide uplift which began in latest Cretaceous time as dominantly vertical movement along arcuate trends. Uplift continued into the Paleocene, and the steeper flanks of some ranges developed into large overturned folds by local compressive forces marginal to the main uplifts. Along segments of maximum uplift, overturned folds were broken and thrust far over the basin synclines in latest Paleocene or earliest Eocene time. Throughout the long period of uplift the adjacent basins were downwarped continuously and received sediment from the rising mountains. The process of uplift by folding and thrusting better explains observed structure of mountain flanks than the older ideas of block uplift along high-angle faults or thrust uplift by regional compression. Fold-thrust structures are best known along the major Wyoming thrust zones bordering, on the south, the Wind River and Granite Mountains and the Washakie and Owl Creek Mountains. Other examples of faulted overturned folds occur in Colorado along the Golden thrust of the Front Range and Willow Creek thrust in western Colorado. In all these areas thrusts are well documented by subsurface control which includes both deep wells and seismic data.

Mountain Flank Thrusting in Rocky Mountain Foreland, Wyoming and Colorado

The vertical succession of sedimentary structures and textures at Galveston Barrier Island, Texas, is identical with vertical successions in two ancient barrier complexes, one in the Lower Cretaceous of Montana and the other in the Lower Jurassic of England. Within both Holocene and ancient examples, there is a gradation upward from (1) irregular interlaminations of siltstone and claystone at the base, through (2) burrowed and generally structureless sandstone, to (3) low-angle and microtrough cross-laminated sandstone, terminating in two of the examples in (4) structureless and rooted sandstone. This sequence represents deposition in (1) lower shoreface, (2) middle shoreface, (3) upper shoreface-beach, and (4) eolian environments, respectively. Analyses of quartz size and content of the Holocene and ancient barriers yield textural and compositional parameters that are environmentally sensitive. Plots of these parameters demonstrate that each of the environments may be distinguished on the basis of thin-section analyses. Consequently, full diameter cores, which show sedimentary structures, may not be necessary for precise environmental interpretation in the subsurface. Indeed, thin sections of sidewall cores may yield significant and reliable environmental interpretations in barrier sandstones. Textural and sedimentary structural similarities between Galveston Island and the ancient examples permit a general model of barrier sedimentation to be developed.

Recognition of Barrier Environments

Growth faults consist of nonsealing fault surfaces and sealing sheared zones that may occur on either the footwall or hanging wall. The properties of sheared zones are assumed to be identical to those of soft sediment that has undergone ductile deformation during mass movement. In cores, the sheared zones display fabrics similar to Riedel shears and are termed wispy, crenulate, conjugate, and meniscate, in order of increasing deformation. Permeabilities and porosities range from 0.1 md and 18% to less than 0.01 md and 8%. Based on limited measurements, initial mercury-injection capillary pressures range from 400 to 550 psia, sufficient to trap an average oil column of 98 m (320 ft). Sheared zones are effective seals because ductile deformation has homogenized the original sediments and resulted in a uniform distribution of small pores. In contrast, the fault surface is a region of extension that is presumed to result in higher permeabilities, low displacement pressures, and the ability to transmit migrating oil and gas from deep source beds to shallow traps. Thus, growth faults can seal in the sheared zone and leak along the fault surface. Sheared zones are distinctive on dip logs. Dips within sheared zones have variable magnitudes and directions, whereas dips adjacent to faults exhibit more uniform patterns resulting from normal drag.

Robert R. Berg

Papers

Capillary Pressures in Stratigraphic Traps

Primary Migration by Oil-Generation Microfracturing in Low-Permeability Source Rocks: Application to the Austin Chalk, Texas

Mountain Flank Thrusting in Rocky Mountain Foreland, Wyoming and Colorado

Recognition of Barrier Environments

Sealing Properties of Tertiary Growth Faults, Texas Gulf Coast