Deep, water-free gas potential is upside to New Albany shale play

Feb. 16, 1998
The New Albany shale of the Illinois basin contains major accumulations of Devonian shale gas, comparable both to the Antrim shale of the Michigan basin and the Ohio shale of the Appalachian basin. 1 The size of the resource, originally assessed at 61 tcf, 2 has recently been increased to between 323 tcf 3 and 528 tcf. 4 According to the 1995 U.S. Geological Survey appraisal, New Albany shale gas represents 52% of the undiscovered oil and gas reserves of the Illinois basin, with another 45%
Terence Hamilton-Smith
Hamilton-Smith LLC
Lexington, Ky.
The New Albany shale of the Illinois basin contains major accumulations of Devonian shale gas, comparable both to the Antrim shale of the Michigan basin and the Ohio shale of the Appalachian basin. 1

The size of the resource, originally assessed at 61 tcf,2 has recently been increased to between 323 tcf3 and 528 tcf.4

According to the 1995 U.S. Geological Survey appraisal, New Albany shale gas represents 52% of the undiscovered oil and gas reserves of the Illinois basin, with another 45% attributed to coalbed methane.

New Albany shale gas has been developed episodically for over 140 years, resulting in production from some 40 fields in western Kentucky, 20 fields in southern Indiana, and at least 1 field in southern Illinois.

Two plays identified

A regional evaluation of the New Albany shale funded by the Gas Research Institute 1 recognized the existence of two different plays in the New Albany shale. One play is accompanied by substantial water production similar to the Antrim shale of the Michigan basin, and the other play lacks any associated water flow like the Ohio shale of the Appalachian basin.

Historical records indicate that all fields in southern Indiana, together with fields in adjacent counties of both Kentucky and Illinois, produced substantial amounts of water, mainly from an underlying carbonate aquifer. In contrast, fields in western Kentucky to the south of the Rough Creek fault zone produced gas from the New Albany shale without significant water due to restricted porosity development in the underlying carbonates.

Most recently, exploration and development have been concentrated on the shallow margin of the basin in southern Indiana and adjacent Kentucky, where reservoir conditions closely approximate those found in the Antrim shale of the Michigan basin. These conditions include abundant water production from a widely distributed stress-release fracture system at depths less than about 1,500 ft.

Many operators have been attracted to this segment of the play, but three main projects dominate current activity.5 Mercury has a 20 well field producing gas for a southern Indiana local distribution company. Jet/LaVanway has 12 wells on production in southern Indiana, with others waiting on infrastructure. Riata Energy has 20 wells in Kentucky just across the Ohio River from the producing areas of southern Indiana, selling gas to a local plant of Olin Corp.

Other operators such as Cabot and Ashland (converted to Blazer Energy and then acquired by the Eastern Group) have found too much water and not enough gas and are seeking to sell their New Albany shale properties.

Shrewsbury revitalized

Relatively unnoticed in the focus of activity on the Antrim-like play in southern Indiana has been the rejuvenation of what is still the largest New Albany shale gas field in the Illinois basin-Shrewsbury field of west-central Kentucky.

This field was discovered in 1938 but was not intensively developed until the late 1970s with the strong rise in gas prices.6 More than 100 wells were drilled in the field area, 91 of which were produced by the field operator, Equitable Life Assurance, selling gas via pipeline to Midwestern Gas Transmission.

Gas production in Shrewsbury field is not accompanied by any significant water flow.

Belden & Blake, North Canton, Ohio, acquired Shrewsbury field in late 1996 and delegated operational responsibilities to its subsidiary, Peake Energy, Ravenswood, W. Va. The field had 67 wells on line and producing at the time of the acquisition.

Peake drilled nine more New Albany shale wells in the field in 1997 and budgeted five new wells in 1998. The two new wells put on production have each steadily produced 30-40 Mcfd on line with no water. Seven wells are awaiting stimulation.

North of Shrewsbury field, Kentucky Natural Gas drilled three New Albany shale tests into the Rough Creek fault zone in the vicinity of Leitchfield. Two of those wells had shut-in pressures of 325 psi at 1,432 ft (top of perforations) and 270 psi at 1,342 ft.7

None of these wells produced water, and all showed abundant fracturing on borehole imaging logs. The results of this drilling show that fracture zones associated with major faults can be well sealed above the New Albany shale, and so can be viable exploration targets.

An economic play?

The economic results of this most recent phase of New Albany shale development are still uncertain.

David Hill of Gas Research Institute in a recent proposal to New Albany shale operators said, "Few NAS projects in this area have established commercial production, and many projects are on the verge of being discontinued."

David Cox of Peake Energy told the Society of Petroleum Engineers eastern regional meeting in Lexington last fall that the lifting costs at Shrewsbury field were the highest of any property operated by Peake.

Hamilton-Smith,4 at a recent Petroleum Technology Transfer Council workshop in Grayville, Ill., emphasized the importance of defining a viable gas market as the first step in New Albany shale exploration. He noted that New Albany shale economics to date have generally not been able to support substantial infrastructure development.

Prospective areas

Recent exploration and development of the New Albany shale has not extended very far from the historically developed areas, and the large majority of the shale in the Illinois basin remains untested.

Hamilton-Smith6 recommended the region south of the Rough Creek fault zone as the most prospective area for water-free gas production from the New Albany shale, at depths as great as 4,000 ft. Southern Illinois to the south of the Cottage Grove fault system also has substantial potential for New Albany shale gas at similar depths.

In the deeper basin the natural fracture system will be closely associated with large-scale faults, domes, and folds rather than the extensive stress-release fracturing in the shallow Antrim-like play.

The fact that stress-release fracturing naturally diminishes with depth has led many operators working exclusively with the Antrim shale analog to disregard the potential of deep (i.e., 1,500 ft) drilling for New Albany shale gas. However, substantial gas production from the Ohio shale of the Appalachian basin at depths of about 3,500 ft and from the Barnett shale of the Fort Worth basin at depths of 7,000 ft proves that deep shale gas production is feasible.

In contrast to stress-release fracturing, tectonic fracturing associated with large-scale basement faults, folds, and domes can persist to great depths. In the deepest part of the basin, marked by vitrinite reflectance values greater than 1.0, shale fracturing probably has been further enhanced by substantial overpressuring during hydrocarbon generation.4 6

In the New Albany shale in particular, the best initial shows to date have been found in the deepest tests drilled in the basin, in Warrick County, southern Indiana.

Two operators, Dart and Eastern Natural Gas, reported initial open flow estimates after stimulation of over 1 MMcfd, from depths as great as 3,500 ft, accompanied by variable amounts of water. Well logs, seismic lines, and regional mapping indicated substantial fracturing associated with strike-slip motion on a major basement fault.4

Although litigation (ENG v. Alcoa) has delayed development of this prospect, reservoir simulation of well test results conducted by two engineering consultants showed reserves of 350-750 MMcf/well.

Even in the relatively shallow part of the basin, Riata Energy found that better shale wells were found at greater depth.5 The best wells in Shrewsbury field are located in the deepest, southwest part of the field, at depths of up to 2,000 ft.

Play directions

The New Albany shale play is about to change direction.

In the Antrim-shale-like shallow play the geological simplicity of a regionally extensive near-surface fracture system has been offset by the costs of water production. In some cases it has not been possible to pump off the water at rates sufficient to draw down the reservoir pressure in the shale and consequently to desorb gas.

To the south of the Rough Creek fault zone in west-central Kentucky, an Ohio shale-like play in the New Albany shale has proven gas production without water, but so far not at sufficient rates to stimulate major exploration interest.

Expansion of the play from its current limits can take place in three directions:

  • Better gas rates can be found deeper in the basin. The Dart and ENG wells had the best initial open flow rates, the largest per well reserves, and greatest depths in the basin to date.
  • Gas production without the costs of handling associated water is found to the south of the Rough Creek fault zone in western Kentucky, in fracture zones associated with major faults, folds, and domes.
  • Illinois is virtually untested for New Albany shale gas. In the only development to date, wells drilled by Hux tested gas at rates up to 100 Mcfd and water at rates up to 100 b/d.
In all cases, firm definition of a local gas market is essential for success in New Albany shale gas exploration.


  1. Hamilton-Smith, T., Hasenmueller, N.R., Boberg, W.S., Smidchens, Z., and Frankie, W.T., Gas production, in Hasenmueller, N.R., and Comer, J.B., eds., Gas potential of the New Albany shale (Devonian and Mississippian) in the Illinois basin, Gas Research Institute, Chicago, GRI-92/0391, 1994, pp. 23-40.
  2. Devonian Shale Task Group, Section III, Resource: National Petroleum Council Commmittee on Unconventional Gas Sources, September 1979, pp. 14-25.
  3. Cluff, R.M., Cluff, S.G., and Murphy, C.M., Devonian shale gas resource assessment, Illinois basin (abs.), AAPG Bull., Vol. 81, No. 9, 1997, pp. 1,547.
  4. Hamilton-Smith, T., Cost-effective exploration for gas in the New Albany shale, in Unconventional Gas Workshop, Dec. 7, 1997, Grayville, Ill., Petroleum Technology Transfer Council, Mid-West Office, 38 pp., 19 figures.
  5. Shirley, K., Plays earning northeast new level of respect, American Oil & Gas Reporter, November 1997, pp. 135-142.
  6. Hamilton-Smith, T., Gas exploration in the Devonian shales of Kentucky, Kentucky Geological Survey, Series 11, Bull. 4, 1993, 31 p.
  7. Scout Check, Mar. 13, 1997.

The Author

Terence Hamilton-Smith is a consultant in Lexington, Ky., who has worked on Devonian shale gas reservoirs for more than 10 years. A graduate of Massachusetts Institute of Technology, he worked for Sohio Petroleum and Hamilton Bros. on the North Slope, the North Sea, and a variety of other domestic and international assignments. The Gas Research Institute, Kentucky Geological Survey, and numerous private companies, including Amoco, Chevron, and Belden & Blake, have supported his work on Devonian shale gas.

Copyright 1997 Oil & Gas Journal. All Rights Reserved.