The Chattanooga Shale

The Upper Devonian fractured black and gray shales and siltstones play encompasses
a large area within the Appalachian basin in which the stratigraphy, thickness, organic
geochemistry, and thermal maturity of the Devonian shale sequence ranges vary widely.
The play is defined, however, by shale gas reservoirs that consist generally of fractured
black shale source rocks that are imbedded with gas-producing gray shales and
siltstones.

Stratigraphy

The Devonian shale sequence was deposited during episodes of subsidence (relative
sea-level rise) and eastward transgression of the marine environment in which the black
and dark gray shales rich in organic matter were deposited.

The unconventional hydrocarbon accumulations in the autogenic gas shales of the
Appalachian Basin are best described as continuous accumulations. Generally, the Devonian
shale sequence produces gas almost everywhere it is drilled so that fields, initially separated by several miles or more during the early phases of development, tend to grow together as the region is explored.

Continuous accumulation differs from conventional hydrocarbon accumulations in several ways. They do not occur above a base of water and they commonly are not density stratified within the reservoir. Although production is significantly affected by fracturing, gas accumulations generally occur independently of broad anticlinal structures.

The distribution of producing areas and the production characteristics of gas-shale reservoirs depend greatly on several factors, including the nature and amount of the organic matter, thermal maturation and enhancement of reservoir porosity and permeability by natural fracture systems.
In places, production may occur over relatively thick stratigraphic intervals and generally is greatest in naturally fracture black shale reservoirs rich in organic matter.

The various fields within the black shale play are complex combination traps. Production is controlled largely by the occurrence of zones of intense natural fracturing within a uniformly gas-saturated shale sequence. Unfortunately, the location, orientation, and intensity of natural fractures do not correlate with the known near-surface fold and fault systems, and are therefore difficult to predict. However, research focusing on the role of reactived basement faults (or fault zones) in causing faults-and/or flexure-related fracturing in overlying shale units has provided a workable exploration rationale.
Such fault lines can be seen directly on seismic lines or inferred from the structural configuration of overlying units.

Reservoirs

The reservoirs in the black shale pay are organic-rich, finely-laminated gas-saturated shales that are unique (unconventional) reservoirs because they serve as the primary gas source rock, the reservoir and the seal. Matrix porosity is low, perhaps ranging from 1.0 to 5.0 percent. Matrix permeability is virtually nonexistent.

Gas content within the black shales varies regionally in accordance with changes in thickness, pressure, organic content, and thermal maturity. Because the shale is virtually impermeable, commercially viable production to date has required an interconnected natural fracture system that can be accessed either by the wellbore or by induced fractures.

Black shale reservoirs store gas in three modes: free matrix gas within pore spaces in the rock matrix, as matrix gas absorbed on to rock components and as free gas within a variable developed system of open natural fractures. Production is sustained by the continual diffusion of free matrix gas into fractures and the replenishment of the free gas by desorption of adsorbed gas with pressure decline.