Shale Gas: A Brief History

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By KATHY SHIRLEY
EXPLORER Correspondent
Tax Break Rekindled Interest
Shale Gas Exciting Again
An Atrium Shale outcrop at the Paxton Quarry in northern Michigan.
Photo courtesy of Gas Research Institute
See related story: Lewis Not Overlooked Anymore
Shale gas production is certainly nothing new in the United States. In fact, the first commercial gas shale well was drilled in New York in the late 1820s – nearly 40 years before Colonel Drake drilled his famous oil well in Pennsylvania.
Still, there’s a new - some might say urgent - sense of excitement when it comes to the role of shale gas production in today’s energy mix, as well as its potential for the coming years.
“Over the next decade we expect the gas industry will continue to expand the shale gas play frontiers as new areas are evaluated and we learn more about the geology of shale gas resources,” said David G. Hill, manager, emerging resources, with the Gas Technology Institute.
Gas shales, he said, are classified as continuous type natural gas plays - accumulations that are pervasive throughout large geographic areas and offer long-lived reservoirs with attractive finding costs.

“The major exploration risk in most shale gas plays is generally not the drilling of a truly dry hole, but rather in not obtaining economically viable gas production rates,” Hill said. “Most shales have very low matrix permeabilities and require the presence of extensive natural fracture systems to sustain commercial gas production rates.”

In shale reservoirs, natural gas is stored three ways:
As free gas within the rock pores.
As adsorbed gas on organic material.
As free gas within the system of natural fractures.
These different storage mechanisms, Hill said, affect the speed and efficiency of gas production.
Modern gas shale production was initially spurred by the Section 29 non-conventional fuels production tax credit, but that tax credit expired in 1992, and operators have continued to expand gas shale programs. Today over 28,000 gas shale wells produce nearly 380 billion cubic feet of gas yearly from five U.S. basins:

Appalachian.
Michigan.
Illinois.
Fort Worth.
San Juan.
In 1998 fractured shale gas reservoirs supplied 1.6 percent, or .3 trillion cubic feet of total U.S. dry natural gas production and contained 2.3 percent or 3.9 trillion cubic feet of total U.S. proved natural gas reserves. Over the past decade shale gas production has increased by a factor of 2.5, growing from 148.6 billion cubic feet of gas in 1989 to 380 billion cubic feet in 1999.
The shale gas resource base in the lower 48 states is significant. According to GTI, gas-in-place resource estimates for the five main gas shale plays total 581 trillion cubic feet of gas, and recoverable resource estimates range from 31 to 76 trillion cubic feet.

These figures are considered conservative since estimates for the Barnett Shale in the Fort Worth Basin and the Lewis Shale (see related story, page 26) are not available.
Hill commented that “each new shale gas play has presented technical challenges that operators have to overcome by identifying and solving shale-specific problems.
“But,” he added, “success in these relatively low-cost plays has sparked a resurgence of industry interest in evaluating the production potential of the shale gas resources present in basins throughout the United States.”

A Stimulating Story
The first shale gas production in the United States came from the Appalachian Basin, where by 1926 the Devonian shale gas fields were the world’s largest known occurrence of natural gas. At year-end 1999 the basin contained over 21,000 gas shale wells, producing approximately 120 billion cubic feet of gas a year.
Technically recoverable resource estimates for the Appalachian Basin range from 14.5 to 27.5 trillion cubic feet of gas.
The basin’s Devonian-age shales extend from southwestern New York to eastern Kentucky and central Tennessee. The majority of its shale gas production has been from the Big Sandy and associated fields in Kentucky and southwestern West Virginia, where the primary target is the Huron member of the Upper Devonian Ohio Shale.
Well recoveries vary considerably, ranging from less than 100 million cubic feet of gas to more than one billion cubic feet. The average well produces 250 to 350 million cubic feet over a productive life of 30 years.
“One of the biggest technical challenges in the Ohio Shale has been in the area of stimulation,” Hill said. “While some wells flow gas naturally, over 90 percent require some form of stimulation to achieve commercial production rates.”

Over the years the Appalachian Devonian shales have been a test bed for a variety of stimulation technologies that include:
“Shooting” a well with gelatinated nitroglycerine.
High energy gas fracturing.
Nitrogen- and carbon dioxide-based foam fracturing.
Straight gas fracturing without proppant.
High angle and horizontal completions.
A number of variations on basic fracturing fluids and chemicals.
Two more recent innovations are the use of liquid carbon dioxide and sand, and cryogenic nitrogen.
As with most stimulation applications, Hill said, no single technique or fluid system has worked universally.
“The proximity to large East Coast markets, low transportation costs, long lived reserves and high success rates will continue to make the Ohio Shale an attractive target in the Appalachian Basin,” he said.
“However, considering the maturity of the play, the greatest challenge to continued success will be expanding the productive limits of historic play areas with new stimulation technologies.”

A Tale of Two Basins
The Antrim Shale in the Michigan Basin spurred the current gas shale interest in the United States.
Initially the Section 29 tax credit spurred activity in the Antrim Shale, but new technology, an understanding of the mechanisms controlling production and operational efficiency gains by operators have sustained activity in the play.
The Devonian-age Antrim Shale reaches a depth of about 3,000 feet in the center of the basin. Operators, however, are developing the shale along the shallow northern and western rim of the basin, where well depths range from 400 to 2,500 feet and wells cost about $240,000 to $280,000 to drill and complete.
The primary targets are the Lachine and Paxton members of the Lower Antrim.
Resources estimates range from 35 trillion to 76 trillion cubic feet of gas, with technically recoverable gas reserves estimated at 11 to 18.9 trillion cubic feet. The average well in the Antrim Shale produces around 116 thousand cubic feet of gas a day, and production has grown from 12 billion cubic feet from 154 wells in 1988 to over 190 billion cubic feet of gas from 6,500 wells in 1999.
In fact, the 221 Antrim Shale wells drilled in 1999 accounted for three-quarters of the drilling activity in the Michigan Basin.
“The Antrim play will continue to develop,” Hill said, “as operators evaluate new completion technologies, recomplete wells in the upper Antrim Shale, conduct restimulation programs and test new areas for production potential.”

The New Albany Shale in the Illinois Basin has a long producing history, too, but activity in this region has not progressed at the same rate as the Ohio Shale or the Antrim Shale.
In the 1990s activity in this play was driven by success in the Antrim. Many of the players in Michigan considered the New Albany a viable target and approached it using the Antrim model for development.
Activity in the New Albany Shale peaked in 1996 with 90 wells, but has since declined to just 16 wells in 1999.
Operators are currently experimenting with various drilling and completion techniques in an attempt to improve well performance and reduce costs. Well costs have ranged from $100,000 to $150,000, depending on water lifting requirements and the type, number and size of stimulation treatments needed.

Efforts also are under way to better identify the mechanisms controlling gas occurrence and productivity.
Gas resource estimates for the New Albany Shale range from 86 to 160 trillion cubic feet of gas with estimates of technically recoverable reserves ranging from 1.9 to 19.2 trillion cubic feet.

The Barnett - and Beyond
Mitchell Energy & Development Co. has been developing the Barnett Shale in the Fort Worth Basin in the northeast sector of central Texas since 1981.
The Mississippian-age Barnett Shale is one of the most uniform statigraphic units in the basin, outcropping along the flanks of the Llano uplift in central Texas, where it is about 30 to 50 feet thick.
The shale dips gently and thickens to the north, reaching a maximum depth of around 8,500 feet and a maximum thickness of almost 1,000 feet near the Texas-Oklahoma border.
Barnett Shale production was first established in the Newark East Field in Wise and Denton counties, where it grew from less than one billion cubic feet of gas from 25 wells in 1985 to 19.2 billion cubic feet from 306 wells in 1995. During the past five years, production has more than doubled to 40.6 billion cubic feet from over 500 wells.
The Barnett is found at 6,500 to 8,000 feet in the Wise and Denton counties area and is about 500 feet thick. It is divided into lower and upper intervals by the Forestburg Limestone.

AFE Oil and Gas Consultants expanded the Barnett Shale play area in 1997 with a discovery in Dallas County, approximately 12 miles southeast of the Newark East Field. The firm continued to expand its play area with three wells in northeastern Tarrent County.
“Initially, Mitchell Energy completed only the lower Barnett interval, using massive hydraulic fracturing treatments,” Hill said. “Well costs typically ranged from $600,000 to $800,000, including $200,000 to $300,000 in stimulation costs.”
In 1998 the firm experimented with a new stimulation technique that employed water as the fracturing fluid, required significantly less proppant and was about 60 percent less expensive than the conventional stimulation treatments.

“The technique proved successful,” Hill said, “and has since been implemented field wide.”
Last September Mitchell Energy demonstrated a technique for economically completing the upper Barnett Shale interval, increasing reserves in their core area by 25 percent, or 250 million cubic feet per well, and expanding the play to previously marginal areas.
This new completion technique in combination with a 50-acre spacing infill well drilling program is expected to allow Mitchell Energy to increase its Barnett Shale gas production and open up new areas for exploitation.

Hill said while the bulk of gas shale production has come from these reservoirs in the San Juan, Appalachian, Michigan, Illinois and Fort Worth basins, there are a multitude of opportunities to expand shale gas activity in other regions of the country.

“Three key advantages of shale gas plays are moderate exploration costs, high success rates and slow production decline rates,” he said. “The rapid growth in the late 1980s and early 1990s in the Antrim Shale, which is being repeated today in the Fort Worth and San Juan basins, is driven by the powerful economic incentives of low risks and low reserve finding costs.
“Each of these plays has presented new technical challenges for operators to overcome,” he added, but “their success has sparked a resurgence of industry interest in evaluating the production potential of shale gas resources in basins throughout the United States.”