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
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
“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
- 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.
- 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
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
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
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,”
“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
“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
“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.”