Devonian (Chattanooga) Shale
Stimulation Project

Tennessee-based independent, Ky-Tenn Oil, Inc., (KTO) has initiated a project to stimulate existing wells that penetrate the Devonian Shale, on its 40,000 acres of leases in Fentress, Morgan and Scott Counties in Tennessee.

Gas production from the Devonian shale is not new. The first shale well was drilled in 1821 in Fredonia, New York to a depth of 27 feet. Initially the well produced enough gas to light 30 burners and was sufficient to light an inn. Later it was deepened to 70 feet and provided enough gas to light the streets and public buildings in Fredonia.

The location, production history, stratigraphic, reservoir and reserve characteristics of the Devonian Shale in the Appalachian Basin are well documented. However, it took a recent combination of price surges in natural gas coupled with more sophisticated stimulation techniques now available to convince Tennessee operators to look more closely at the Chattanooga shale. Until very recently, Tennessee operators believed the geologists were correct in their assumption that the Devonian shale potential stopped at the Kentucky-Tennessee state line.

The Shale Production really doesn't stop at the state line

Most geological maps of the Appalachian Basin, like the one on the previous page, show the Devonian Shale play stopping at the Kentucky-Tennessee state line.
That assumption was made because there had been very little Devonian Shale activity in Tennessee prior to 2004.

Only a handful of Chattanooga Shale wells produced gas naturally in Tennessee. And only one shale well in the state had been successfully stimulated with nitrogen.

perators agreed with geologists that these producing wells were anomalies. The general consistence was that the 40-60 foot Chattanooga shale sections weren't targets for stimulation.

However, as gas prices increased, a few Tennessee operators began to studying the shale. They discovered that all shales are not alike and that the thin section of Chattanooga shale had potential as a commercial producer.

They began experimenting with very expensive nitrogen and sand stimulations. In the process of developing stimulation programs for the shale, the operators began studying more and more data on the Devonian Shale.

The following is a summary of two geological papers prepared for The Atlas of Major Appalachian Gas Plays, published by the U.S. Department of Energy, the Gas Research Institute and the West Virginia Geological and Economical Survey in 1996.

Upper Devonian Fractured Black & Gray Shales and Siltstones, written by Robert C. Milic, U.S. Geological Survey and Upper Devonian Black Shales, written by Ray Boswell, EG&G, TSWV, Inc.

Location

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.

Production and Reserves-

Cumulative production values for individual black shale wells range from 50 to 900 MMcfg, although the majority of wells produce less than 300 MMcfg.

A way to calculate the resource potential of the play is to use existing wells and field production data, estimated drainage areas, and the area of the play.

Weighted average data (National Petroleum Council 1992) for the ultimate recovery of 49 wells in Roane and Kanawha counties near the emerging areas of West Virginia is about 274 MMcf per well. In comparison, Brown (1976) studied more than3,000 wells in West Virginia an calculated that, in an area of 1,500 square miles, ultimate recovery of shale gas in the state is 893a bcf, for an average ultimate recovery of about 300MMcf per well.

Cumulative production from the Devonian black shales in the Appalachian Basin is estimated at approximately 3tcf (de Witt 1986) from roughly 10,000 wells, or approximately 300 MMcfg per well

Initial open flows are a relatively good way to predictor of ultimate well performance in many areas. A variety of well production decline curves for the various regions of the play are shown in Figure UDs-17.

In general, the initial potential and cumulative production of shale wells decreases to the north and east of the Big Sandy area.

A 1977 study determined that 77 percent of wells in eastern Kentucky delivered final open flow potentials in excess of 300 Mcfg/d; for West Virginia, the probability is only 51 percent, whereas in Ohio, only 10 percent of wells demonstrate such potential.

Ultimate recovery efficiencies in black shale reservoirs are very low because only that portion of the gas resource contained as free gas within fractures or pores connected to the wellbore or adsorbed onto rock constitutes in very close proximity to fractures or pores can be produced given current technology. A 1976 report determined that the typical shale well in West Virginia will only produce 8.2 percent of the gas within a 150-acre drainage area. Another 1976 study obtained very similar results based on Kentucky data.

In the mid 1920s to roughly, approximately 90 percent of all shale wells were stimulated through the denotation of 4,000 to 8,000 pounds of gelatinized nitroglycerin. In only 11 percent of the cases, was shooting unable to establish production in Kentucky.

After 1950, stimulation techniques used the forced injection of water and sand to induce and prop open fractures. More recently, nitrogen, nitrogen-foam, and CO2 fracturing techniques have been investigated by various operators.

Future Trends

Technological improvements may greatly facilitate exploration and development of naturally fractured shale-gas reservoirs. It is anticipated that use of modern seismic technology to identify areas of low-density, gas-bearing decollement-related fractured reserves may increase success ratios significantly during exploration.

In addition improvements in well drilling, stimulation, completion practices, and the use of directional drilling techniques may increase productivity, so that in the future, more marginal wells may be completed as commercial.

KTO Project

In its Chattanooga well stimulation program, KTO is utilizing a large nitrogen, acid, sand stimulation program developed especially for KTO by Universal Well Service. A description of the treatment program is attached.

KTO seeks out existing wells that have been drilled through the shale and which there is often the presence of gas seen in the shale as indicated by the temperature log.

Most wells in the Fentress, Morgan County area in which KTO has leases were only drilled a short distance into the shale. Therefore, KTO expects to deepen most wells before the shale can be treated.

Copies of the shale section of logs are several wells are attached. The first is the log of the Pemberton #1, on which a successful treatment was conducted.

The remaining logs are candidates for future treatment.