Shale Gas: A Global Resource

Shale Gas: A Global Resource
Producing commercial quantities of natural gas from organic-rich shales was
uncommon a decade ago. Success in the Barnett Shale of central Texas, USA,
launched a new way of thinking about shale source rocks. The techniques used there
were applied to other North American basins where conditions were favorable for
coaxing natural gas from source rocks. Successful gas production from shales soon
followed in numerous locations in the US and Canada, generating exploration interest
on a global scale as companies now attempt to replicate that achievement.
Chuck Boyer
Pittsburgh, Pennsylvania, USA
Bill Clark
Oklahoma City, Oklahoma, USA
Valerie Jochen
College Station, Texas, USA
Rick Lewis
Camron K. Miller
Dallas, Texas
Oilfield Review Autumn 2011: 23, no. 3.
Copyright © 2011 Schlumberger.
28
Shales are the most abundant form of sedimentary rock on Earth. They serve as the source
rocks for hydrocarbons migrating into permeable reservoirs and act as seals for trapping oil
and gas in underlying sediments. Until recently,
the oil and gas industry generally regarded them
as nuisances to be tolerated while drilling to
target sandstone and limestone reservoirs. But
geologists and engineers have begun to view a
specific type of shale—organic-rich shale—with
a newfound appreciation. If endowed with the
right characteristics, organic-rich shales have
the potential to serve not only as sources of
hydrocarbons but also as reservoirs to be produced. Finding and producing gas from shale
formations, initially a North American phenomenon, has become a global pursuit for many
exploration companies.
The catalyst for the recent boom in shale
exploration is the Barnett Shale in Texas. It took
20 years of experimenting before the play was
considered economically viable. Two technologies—fracture stimulation and horizontal drilling—were developed and applied at the right
time to enable this success.
While the most interest and greatest financial
investment have been directed at basins in North
America, operators are seeking to replicate the
success in other parts of the world. In countries
that have little current hydrocarbon production
of their own, such as those in Europe, shale
exploration takes on great importance. However,
interest is not limited to North America and
Europe; sites across the globe are attracting
investment capital. This article reviews the
current state of worldwide gas shale exploration
and development.
Unconventional Resources
Organic-rich shale deposits with potential for
hydrocarbon production are referred to as both
unconventional reservoirs and resource plays.
Unconventional gas reservoirs refer to low- to
ultralow-permeability sediments that produce
mainly dry gas. Reservoirs with permeability
greater than 0.1 mD are considered conventional,
and those with permeability below that cutoff
are called unconventional, although there is no
scientific basis for such a designation.
According to a more recent definition, unconventional gas reservoirs are those that can be produced neither at economic flow rates nor in
economic volumes unless the well is stimulated by
hydraulic fracture treatment or accessed by a horizontal wellbore, multilateral wellbores or some
other technique to expose more of the reservoir to
the wellbore.1 This definition includes formations
composed of tight gas sands and carbonates, as
well as resource plays such as coal and shale.2 The
term resource play refers to sediments that act as
both the reservoir and the source for hydrocarbons. Unlike conventional plays, resource plays
cover a wide areal extent and are not typically confined to geologic structure.
Oilfield Review
Producing hydrocarbons from shale deposits
is nothing new; the practice predates the modern
oil industry. In 1821, decades before the first oil
well was drilled, a commercial shale gas well was
drilled in Fredonia, New York, USA.3 By the 1920s,
the world’s most prolific natural gas production
came from similar shale deposits in the nearby
Appalachian basin. The methods used then for
exploiting gas shales little resemble current practices. Operators drilled vertical wells that produced low flow rates. However, successful
production of natural gas from the Appalachian
basin proffered hope for those who later sought to
tap the Barnett Shale and similar resource plays.
Development of the Barnett Shale traces
its roots to 1981 when Mitchell Energy &
Development Corporation drilled a well exclusively for the production of gas from shale. There
was no instant gratification; 20 years of drilling
and completion innovation, along with increases
in commodity pricing, created the environment
that brought the play commercial viability.
Hydraulic fracture stimulation was the first
technology to unlock the gas trapped in shales.
This practice creates permeability in rocks where
very little exists naturally. Fracturing shale from
vertical wells produced high initial production
flow rates, followed by rapid falloff. Operators
realized that more contact with the reservoir was
needed to avoid these rapid declines. Thus, along
with hydraulic fracturing, the second enabling
technology—the ability to drill extended-reach
horizontal wells—allowed contact with significantly more reservoir rock than is possible from
vertical wellbores.
By applying these two technologies together,
companies operating in the Barnett Shale proved
that economic volumes of hydrocarbons could be
liberated from the shale source rocks. Following
this success, operators rushed to similar basins
in search of shales that could become the “next
Barnett.” Rocks that had been largely ignored by
the E&P industry were suddenly the subject of
great interest.
As evidence of the success in producing gas
from shales, in 2008, the Barnett Shale became the
largest gas-producing play or formation in the US,
contributing 7% of all the natural gas produced in
the contiguous 48 states for that year.4 Success in
other gas shale plays followed. In March 2011,
after just three years of development, the prolific
Haynesville-Bossier Shale in Louisiana and east
Texas produced 159.1 million m3/d [5.62 Bcf/d] of
1. US National Petroleum Council (NPC): “Unconventional
Gas Reservoirs—Tight Gas, Coal Seams, and Shales,”
Washington, DC, working document of the NPC Global Oil
& Gas Study, Topic Paper no. 29, July 18, 2007.
2. Ground Water Protection Council and ALL Consulting:
“Modern Shale Gas Development in the United States:
A Primer,” Washington, DC, US Department of Energy
Office and Fossil Energy and National Energy Technology
Laboratory, 2009.
For more on coalbed methane: Al-Jubori A, Johnston S,
Boyer C, Lambert SW, Bustos OA, Pashin JC and Wray A:
“Coalbed Methane: Clean Energy for the World,”
Oilfield Review 21, no. 2 (Summer 2009): 4–13.
3. US Department of Energy (DOE) and National Energy
Technology Laboratory (NETL): “Shale Gas: Applying
Technology to Solve America’s Energy Challenges,”
Washington, DC, US DOE and NETL (March 2011),
http://www.netl.doe.gov/technologies/oil-gas/
publications/brochures/Shale_Gas_March_2011.pdf
(accessed August 22, 2011).
4. Warlick D: “A Current View of the Top 5 US Gas Shales,”
Oil & Gas Financial Journal, (February 1, 2010), http://
warlickenergy.com/oil-gas-articles/a-current-view-ofthe-top-5-us-gas-shales/ (accessed October 17, 2011).
Autumn 2011
29
Annual shale gas production, Tcf
5.0
4.5
Eagle Ford Shale
4.0
Marcellus Shale
Haynesville-Bossier Shale
3.5
Woodford Shale
3.0
Fayetteville Shale
2.5
Barnett Shale
2.0
Antrim Shale
1.5
1.0
0.5
0.0
2000
2001
2002
2003
2004
2005
Year
2006
2007
2008
2009
2010
> A rapid increase in gas production from shales in the US. Since 2000, annual production of gas from shales in
the US has risen from an almost insignificant amount to nearly a quarter of the total gas produced. The seven
plays shown produced an estimated 4.5 Tcf [127.4 billion m3] of natural gas in 2010. The total produced from
all US shale resource plays was 4.87 Tcf [137.9 billion m3] of dry gas. (Adapted from US DOE and NETL,
reference 3.)
Global Perspectives
E&P companies have routinely produced hydrocarbons from shale. For instance, operators in
Brazil, Estonia, Germany and China produce oil
from shales by retorting.8 However, as of 2011,
there were no commercial operations producing
gas from shales outside North America. That situation may change rapidly. Gas shale exploration
is ongoing in South America, Africa, Australia,
Europe and Asia. Around the world, E&P companies are acquiring and analyzing seismic data,
drilling exploratory wells and evaluating formations for gas production capabilities. As assessment of global shale resources has continued,
estimates for resource potential have gone up
dramatically (next page, top). A recent study estimated that the global natural gas resource potential from shales was 25,300 Tcf [716 trillion m3].
However, in many cases, significant challenges lie
in the path of development.
Unlike shale development in the US, where
smaller operators were instrumental in much of
the activity, European gas shale exploration and
development tend to be dominated by large
multinational energy companies and national oil
companies. Companies with substantial acre­age
positions in Europe include ExxonMobil
Corporation, Total S.A., ConocoPhillips Company
and Marathon Company. With limited experience
in shale exploration and development, these companies are partnering with companies that developed the North American gas shale industry. For
example, Total has acquired a large stake in
Chesapeake Energy Corporation, an active player
in several US shale developments. ExxonMobil
recently acquired XTO Energy Inc, a move seen by
many energy analysts as an attempt to acquire
expertise in developing shale resources.9
Beyond the lack of existing technical experience, several other factors impede development
of shale resources in Europe, Asia and South
America. Sourcing large quantities of water for
drilling and stimulation operations is a major
concern, as is the limited availability of oilfield
service equipment—primarily the type used for
5. US Energy Information Administration (EIA): “Haynesville
Surpasses Barnett as the Nation’s Leading Shale Play,”
Washington, DC, US EIA (March 18, 2011), http://www.eia.
gov/todayinenergy/detail.cfm?id=570 (accessed
October 6, 2011).
6. Kuuskraa V, Stevens S, Van Leeuwen T and Moodhe K:
“World Shale Gas Resources: An Initial Assessment of
14 Regions Outside the United States,” Washington, DC,
US DOE EIA, April 2011.
7. Monteith G: “Ohio Shale’s Energy Potential: It Could Be
Big,” hiVelocity (May 5, 2011), http://www.
hivelocitymedia.com/features/Shale5_5_11.aspx
(accessed October 16, 2011).
8. Allix P, Burnham A, Fowler T, Herron M, Kleinberg R
and Symington B: “Coaxing Oil from Shale,” Oilfield
Review 22, no. 4 (Winter 2010/2011): 4–15.
9. Durham LS: “Poland Silurian Shale Ready for Action,”
AAPG Explorer 31, no. 2 (February 2010): 14, 18.
10.Kuuskraa et al, reference 6.
11.Arthur JD, Langhus B and Alleman D: “An Overview of
Modern Shale Gas Development in the United States,”
ALL Consulting (2008), http://www.all-llc.com/
publicdownloads/ALLShaleOverviewFINAL.pdf
(accessed September 28, 2011).
natural gas, eclipsing the Barnett Shale’s 152.9
million m3/d [5.40 Bcf/d].5 In 2010, 137.9 billion m3
[4.87 Tcf] of dry gas was produced from the various
US shale resource plays (above). This amounted to
23% of the annual production in the US.6 And the
future for producing gas from shales appears
bright. The Marcellus Shale in the Appalachian
region of the eastern US, which is only now being
explored and developed, has been projected to
have the potential to surpass production of both
the Barnett and Haynesville-Bossier shales.7
Exploration companies are now turning their focus
to other regions with the hope of developing
untapped shale resources.
30
Oilfield Review
hydraulic fracturing. Also, there are potential
land use issues in densely populated areas of
western Europe. Whereas the mineral rights for
much of the land in the US are controlled by landowners, this is not the case in other countries,
where the state owns below-ground resources.
The potential conflicts between surface owners
and resource developers pose perhaps the most
daunting challenge to development in Europe.
In the rush to develop, it is difficult to ignore
nontechnical issues, which include geopolitics,
public perception and a host of other concerns.
Despite these factors, and because of the gamechanging nature of gas shale plays in the US,
global interest has heightened. A comprehensive
report published by the US Energy Information
Administration (EIA) in 2011 assessed 48 gas
shale basins in 32 countries and reviewed the
current state of shale development (below).10
Based on this report, the world appears poised
for a shale gas revolution.
1997 Rogner Study, Tcf
2011 EIA Study, Tcf
North America
Region
3,842
7,140
South America
2,117
4,569
549
2,587
Africa
1,548
3,962
Asia
3,528
5,661
Australia
2,313
1,381
Other
2,215
Not available
Total
16,112
Europe
25,300
> Shale gas estimates. A 1997 study estimated global shale gas reserves at 16,112 Tcf [456 trillion m3].
The 2011 US EIA study increased that estimate by almost 60% to 25,300 Tcf [716 trillion m3]. [Adapted
from Rogner H-H: “An Assessment of World Hydrocarbon Resources,” Victoria, British Columbia,
Canada: Institute for Integrated Energy Systems, University of Victoria (IESVic, 1997) and Kuuskraa et
al, reference 6.]
Shale Gas Assessments
United States—Currently, the only commercial
shale resource plays are located in North
America, with the majority in the US. The
Marcellus Shale in northeastern US is by far the
largest play, with an estimated areal extent of
246,000 km2 [95,000 mi2]. This is followed by the
New Albany Shale at about half that size.11 Other
Established basins with
resource estimate
Potential basins without
resource estimate
Countries with
unknown potential
> Global shale gas resources. The US EIA studied 14 regions for shale gas potential. Vast land masses in Russia, the Middle East and Africa were not
included in the report (gray shade). Reasons cited for not including these regions in the report were scarcity of exploration data or the presence of
abundant reserves in conventional reservoirs, which make shale gas unattractive—for the present. (Adapted from Kuuskraa et al, reference 6.)
Autumn 2011
31
major gas shales in the US range from 13,000 to
30,000 km2 [5,000 to 12,000 mi2], some of which
have proved to be prolific producers (below).
Based on 2011 estimates, the production
leaders with the highest combined daily rates
are the Barnett and Haynesville-Bossier shales.
Ranking by production, although a significant
indicator, may be misleading because different
plays have experienced varying levels of development. When US plays are ranked instead by estimates of original gas in place (GIP), the
Marcellus Shale at 42.5 trillion m3 [1,500 Tcf]
Lower Besa
River
Canada—Numerous basins in Canada have
significant shale gas potential. The largest are
located in western Canada and include the
Horn River basin, Cordova embayment, the
Laird basin, the Deep basin and the Colorado
group. These five basins contain a combined
estimate of 37.6 trillion m3 [1,326 Tcf] GIP, of
which 10 trillion m3 [355 Tcf] is considered
technically recoverable.13
The target sediments in the Horn River,
Cordova and Laird basins are of Devonian age,
and the main formations of interest are the
leads all others. Although the Marcellus Shale
appears to have the greatest potential, operators
in the region have only recently begun to explore
and develop the play. Of the shales that are
actively being produced today, the largest is the
Haynesville-Bossier Shale with an estimated
original GIP of 20.3 trillion m3 [717 Tcf].
The Barnett Shale comes next at 9.3 trillion m3
[327 Tcf].12 But several shale resources are currently in production. Some of the more notable
are the Fayetteville, Woodford, Antrim, Eagle
Ford and New Albany shales.
Horn River, Cordova
and Laird basins
Montney
Doig
Phosphate
Deep basin Muskwa, Otter Park,
Evie and Klua shales
CANADA
Colorado Group
Frederick
Brook
Niobrara*
Heath**
Cody
Bakken
***
Utica
Horton Bluff
Gammon
Mowry
Hilliard-BaxterMancos-Niobrara
Antrim
Niobrara*
USA
Mancos
MontereyTemblor
Hermosa
PierreNiobrara
Lewis
New
Albany
Chattanooga
Fayetteville
Bend
New Caney
Floyd-Neal
Avalon
Barnett
Eagle Ford,
La Casita
Sabinas basin
MEXICO
600
400
1,200 km
800 mi
Tuscaloosa
Haynesville-Bossier
Basins
Shallowest or youngest
Pearsall
Intermediate depth or age
Burgos basin
Tuxpan basin
Prospective shale plays
Stacked plays
Eagle Ford
Eagle Ford,
Tithonian
Conasauga
Current shale plays
BarnettWoodford
0
Marcellus
Excello-Mulky
Woodford
Monterey
0
Utica
Tampico basin
Pimienta,
Tamaulipas
Deepest or oldest
* Mixed shale and chalk play
** Mixed shale and limestone play
*** Mixed shale and tight dolostonesiltstone-sandstone play
Maltrata
Veracruz basin
> North America shale plays. (Adapted from Kuuskraa et al, reference 6.)
32
Oilfield Review
Muskwa, Otter Park, Evie, Klua and lower Besa
River shales. Several operators have been active
in these areas with positive results. The Triassicage Montney Shale and the Doig Phosphate are
located in the Deep basin. As of July 2009, 234
horizontal wells had been drilled into the
Montney Shale and were producing 10.7 million
m3/d [376 MMcf/d] of natural gas.14
Eastern Canada has several potential shale
plays, although they have not been as extensively
studied as those in the west. Prospective areas
include the Canadian portion of the upper
Ordovician-age Utica Shale in the Appalachian
fold belt, which straddles the border with the US
and has an estimated 4.4 trillion m3 [155 Tcf] of
GIP, of which 877 billion m3 [31 Tcf] is technically recoverable. Few wells have been drilled in
the Utica formation, and gas has been recovered
during testing but at low rates.
The lacustrine Horton Bluff Shale in the
Windsor basin is much smaller, with
255 million m3 [9 Tcf] of GIP, of which an estimated 56.6 billion m3 [2 Tcf] is technically recoverable. Farther west, the Frederick Brook Shale
in the Maritimes basin of New Brunswick is in
preliminary stages of exploration and evaluation.
Mexico—Organic-rich and thermally mature
Jurassic- and Cretaceous-age shales are found in
Mexico. (For more information on characteristics
of organic shales, see “Shale Gas Revolution,”
page 40.) They are similar to productive gas
shales of relative age in the US, such as the Eagle
Ford, Haynesville-Bossier and Pearsall shales.15
Potential shale resources are located in northeast and east-central Mexico, along the Gulf of
Mexico basin. The shales targeted for exploration
also served as the source rock for some of
Mexico’s largest conventional reservoirs.
Although little gas shale exploration activity
has been reported in the five basins in Mexico
studied by the US EIA, there is an estimated
12.Arthur et al, reference 11.
13.Kuuskraa et al, reference 6.
14.National Energy Board, Canada: “A Primer for
Understanding Canadian Shale Gas—Energy Briefing
Note,” Calgary: National Energy Board, Canada
(November 2009), http://www.neb-one.gc.ca/clf-nsi/
rnrgynfmtn/nrgyrprt/ntrlgs/prmrndrstndngshlgs2009/
prmrndrstndngshlgs2009-eng.html (accessed
October 10, 2011).
15.Salvador A and Quezada-Muñeton JM: “Stratigraphic
Correlation Chart, Gulf of Mexico Basin,” in Salvador A
(ed): The Geology of North America, Volume J, The Gulf
of Mexico Basin. Boulder, Colorado, USA: The
Geological Society of America (1991): 131–180.
16.Kuuskraa et al, reference 6.
17.Weeden S: “Mexico Aims to Tap World’s Fourth Largest
Shale Gas Reserves,” Hart Energy E&P, (August 26, 2011),
http://www.epmag.com/2011/August/item87574.php
(accessed September 20, 2011).
18.Kuuskraa et al, reference 6.
Autumn 2011
PERU
BOLIVIA
BRAZIL
PARAGUAY
Paraná basin
Chaco basin
CHILE
ARGENTINA
URUGUAY
SOUTH AMERICA
Neuquén
basin
San Jorge
basin
AustralMagallanes
basin
0
0
Prospective basin
500
1,000 km
300
600 mi
> South America shale basins. (Adapted from Kuuskraa et al, reference 6.)
67 trillion m3 [2,366 Tcf] of GIP, of which
19.3 trillion m3 [681 Tcf] is judged to be technically recoverable.16 The five basins of interest for
shale development are the Burgos (which
includes the Eagle Ford and Tithonian shales),
Sabinas (which includes the Eagle Ford and
Tithonian La Casita shales), Tampico (Pimienta
Shale), Tuxpan (Pimienta and Tamaulipas shales)
and Veracruz (Maltrata Shale). Although there is
considerable interest in developing shale reservoirs in Mexico, many of the organic-rich shales
are structurally complex from overthrusting, or
they are more than 5,000 m [16,400 ft] deep,
which is too deep for development using current
technology. The greatest potential targets are in
the north—the Eagle Ford and Tithonian shales
of the Burgos and Sabinas basins.
Across the Rio Grande River in south Texas,
the Eagle Ford Shale has produced both gas and
oil. Because this formation extends across the
border into the Burgos and Sabinas basins of
Mexico, successful production on the US side of
the border holds promise for similar results on
the Mexican side.
In its first exploratory shale gas well, Mexico’s
national oil company Petróleos Mexicanos
(Pemex) Exploration and Production recently
reported a successful gas test from the Eagle
Ford Shale in the Burgos basin. Production commenced in May of 2011 with a rate of approximately 84,000 m3/d [3.0 MMcf/d]. Pemex plans to
drill 20 additional wells in the near future to further evaluate the resource potential of the five
listed basins.17
South America—Several potential gas shale
basins are located in South America (above).
Argentina has, by far, the largest resource potential, with an estimated 77 trillion m3 [2,732 Tcf] of
GIP, of which 21.9 trillion m3 [774 Tcf] is considered technically recoverable.18 Brazil follows with
33
25.7 trillion m3 [906 Tcf], of which 6.4 trillion m3
[226 Tcf] is considered recoverable. Chile,
Paraguay and Bolivia also have sizable resources.
Uruguay, Colombia and Venezuela have some limited potential for shale development.
The Neuquén basin, in west-central
Argentina, appears to have some of the greatest
potential for gas shale development. The region
is already a major oil and gas producer from conventional and tight sandstones. The middle
Jurassic Los Molles Formation and the Early
Cretaceous Vaca Muerta Formation contain
organic-rich sediments. These two deepwater
marine shales sourced most of the oil and gas
fields in the Neuquén basin.
The Vaca Muerta Formation has some of the
best characteristics for development with high
average total organic carbon (TOC) levels (4.0%),
moderate depth—2,440 m [8,000 ft]—and overpressured conditions.19 The Los Molles Formation
is more mature than the Vaca Muerta and is
found at an average depth of 3,810 m [12,500 ft].
Although covering a larger geographic area,
lower TOCs (1.5% average) in the Los Molles
Formation provide less net GIP than in the Vaca
Muerta Formation. However, there are richer sections in the Los Molles Formation with TOCs
averaging 2% to 3%. Repsol YPF, S.A., recently
began drilling, completing, fracture stimulating
and testing wells in the Neuquén basin and
successfully completed an oil producer in the
Vaca Muerta Formation.20 Apache Corporation,
Argentina, recently completed a Los Molles shale
well that yielded significant quantities of gas.21
Central Patagonia’s San Jorge basin accounts
for 30% of Argentina’s conventional oil and gas
production. The Late Jurassic and Early
Cretaceous Aguada Bandera Shale was the predominant source rock for these accumulations.
With good thermal maturity across most of the
basin and middle to high TOCs, the Aguada
Bandera Shale has potential for shale gas production. It is found at depths between 3,487
and 3,706 m [11,440 and 12,160 ft]. The lacustrine depositional environment of these sediments poses a potential risk for development
because lacustrine shales are viewed as generally worse targets than marine shales.22
Another lacustrine shale, the Early
Cretaceous Pozo D-129 shale formation, is also
located in the San Jorge basin. It is consistently
915 m [3,000 ft] thick in the central part of the
basin, and early analysis of the sediments indicates moderate TOC values and good thermal
34
maturity. The best prospects for gas shale developments are in the central and northern parts of
the basin because of the oil-prone nature in the
southern portions.
The Austral-Magallanes basin in southern
Patagonia straddles the Argentina-Chile border.
The Chile portion of the basin, Magallanes,
accounts for essentially all of the country’s oil production. The main source rock for the basin is the
lower Cretaceous lower Inoceramus Formation,
which contains organic-rich shale deposits.
This formation is approximately 200 m [656 ft]
thick, found at depths of 2,000 to 3,000 m
[6,562 to 9,842 ft] and has low to medium
TOC values.23
The Chaco-Paraná basin is immense, encompassing an area in excess of 1,294,994 km2
[500,000 mi2]. The basin covers most of Paraguay
and parts of Brazil, Uruguay, Argentina and
Bolivia. It has not been extensively explored;
there are fewer than 150 wells drilled across the
entire basin. The Devonian-age Los Monos
Formation contains several marine shale deposits. The most promising is the San Alfredo Shale,
which is found as a thick, monotonous layer of
black shale overlying a sandy unit. Although it
can be as much as 3,658 m [12,000 ft] thick, only
about 600 m [2,000 ft] are thought to have
organic richness.24 The little information that is
available indicates a shale matrix that has good
characteristics for fracture stimulation.
Based on assumed thickness, thermal maturity and gas saturations, and using data from the
few wells drilled across the basin, engineers
have estimated a conservative 59 trillion m3
[2,083 Tcf] of GIP, with 14.8 trillion m3 [521 Tcf]
technically recoverable.25
Europe—Europe has many basins with shale
gas prospects (next page). Because it appears to
have some of the greatest potential, Poland is one
of the most active countries for gas shale exploration in Europe. The Silurian-age Baltic and
Lublin basins run north-central to southeast
across the country and are bounded by the TransEuropean fault zone. The Podlasie basin is
located to the east of these two basins. The
Lublin and Podlasie basins are similar to each
other and are differentiated from the Baltic basin
by geologic features and regional tectonic faulting. Estimated gas in place for these three basins
is 22.4 trillion m3 [792 Tcf] GIP, of which 5.3 trillion m3 [187 Tcf] is considered technically recoverable.26 Although the Podlasie basin has some of
the best reservoir properties, the Baltic basin is
by far the largest in areal extent and total GIP.
A number of exploration companies are
active in Poland, and the first shale exploration
well was drilled in the Baltic basin in 2010. The
vertical evaluation well was a joint venture
between 3Legs Resources plc and ConocoPhillips
Company. BNK Petroleum Inc has drilled and
tested wells in the Baltic basin, targeting
Silurian- and Ordovician-age formations.27
With an estimated 20.4 trillion m3 [720 Tcf] of
GIP and 5.1 trillion m3 [180 Tcf] recoverable,
France closely follows Poland in estimated gas
shale resources.28 These resources are located
principally in the Paris basin and Southeast
basin. The Paris basin contains two organic-rich
shales, the Toarcian black shale formation and
Permian-Carboniferous shales. Portions of the
Toarcian shales are thermally immature and
high in oil content, thus limiting their gas potential. The more mature Permian-Carboniferous
shales—ranging in age from Pennsylvanian to
Late Permian—are deeper and less explored
than those in the northern Paris basin. Average
shale thickness is around 350 m [1,150 ft]
although at the basin’s eastern margin, thicknesses of more than 2,200 m [7,200 ft] can be
found in isolated sections. Minimal data are
available from well logs, so gas estimates are
based on extrapolated assumptions.
Most of the exploration in the Paris basin has
been directed at shale oil, rather than gas.
Recently, however, E&P companies have been
targeting the deeper resource plays lying in the
gas window. The most promising shale formations
in the Southeast basin are the upper Jurassic
Terres Noires black shales and lower Jurassic
Liassic black shales. The eastern portion of the
Terres Noires Shale is in the gas window, while
the western edges are still in the wet gas–oil window. Because it was once deeper but uplifted
along its western margin, the Liassic shale is generally more thermally mature than the Terres
Noires Shale. Although the resource potential of
the Liassic shale is considered greater than that
of the Terres Noires Shale, its higher clay content
makes it more difficult to fracture stimulate.
Currently, there is a moratorium on research
and drilling for shale oil and gas in France, pending environmental impact studies.29 Of even
greater consequence is a government ban on all
hydraulic fracturing in France, which was
enacted in June of 2011.30 Shale gas extraction is
not expressly prohibited, but without the ability
to apply fracturing technology, commercial viability of resource plays is difficult to realize.
Oilfield Review
736 billion m3 [26 Tcf] of GIP and 198 billion m3
[7 Tcf] recoverable in the Posidonia Shale and
254 billion m3 [9 Tcf] of GIP and 56.6 billion m3
[2 Tcf] recoverable in the Wealden Shale. The
deeper and very mature Carboniferous Namurian
Shale contains an estimated 1.8 trillion m3
[64 Tcf] GIP with 453 billion m3 [16 Tcf] recoverable.32 Several companies are currently exploring
in both Germany and the Netherlands.
Farther north, the Alum Shale extends
through Norway, Sweden and Denmark. The areas
that are in the gas window offer promise for production; however, data are sparse. Based on available data, the estimated GIP is 16.7 trillion m3
To the north of France, the North Sea–
German basin extends along the North Sea from
Belgium, across the Netherlands to Germany’s
eastern border. Within this basin are a number of
formations with shale gas potential, including
the Posidonia (located in isolated portions of the
Netherlands and Germany), the Wealden
(Germany) and the Carboniferous Namurian (the
Netherlands) shales.31
Significant volumes of the Posidonia and
Wealden shales are thermally immature and only
isolated sections have gas potential. Potential is
low in both these shales with estimates of
[589 Tcf] with 4.2 trillion m3 [147 Tcf] considered
technically recoverable.
The Pannonian-Transylvanian basin covers
most of Hungary, Romania and Slovakia. Marine
sediments deposited in this basin during the
Oligocene are believed to be the source for most of
Hungary’s conventional hydrocarbons. Although
the shales have been exposed to a very high geothermal gradient, which has accelerated maturation of the organic material, the clay-rich rocks are
of poor quality for production of shale gas.
Exploration is in the early speculative stage; some
initial testing has been discouraging.
NORWAY
SWEDEN
Northern
petroleum
system
IRELAND
Southern
petroleum
system
UK
Weald basin
GERMANY
AUSTRIA
Po basin
CROATIA
Ebro
basin
SPAIN
ITALY
PORTUGAL
Podlasie
basin
POLAND
Trans-European
fault
Lublin
basin
Molasse
basin
Vienna basin
Aquitane
basin
Southeast
basin
LITHUANIA
BELARUS
CZECH
REP.
FRANCE
Prospective basin
Baltic
basin
North Sea–
German basin
THE
NETHERLANDS
BELGIUM
0
0
500
UKRAINE
SLOVAKIA
MOLDAVIA
HUNGARY
Pannonian–
Transylvanian
basin
BOSNIA
& HER.
CarpathianBalkanian
basin
ROMANIA
SERBIA
BULGARIA
ALBANIA
Prospective area
750
RUSSIA
LATVIA
DENMARK
Paris
basin
LusitanianPeniche
basin
ESTONIA
Alum Shale
1,500 km
MACEDONIA
GREECE
TURKEY
1,000 mi
> Europe shale basins. (Adapted from Kuuskraa et al, reference 6.)
19.TOC governs the resource potential of shale.
Exploration targets typically have TOC values in the
range of 2% to 10%.
20.OilandGasInvestor.com: “Argentina’s Neuquén Basin
Shales,” http://www.oilandgasinvestor.com/article/
Argentinas-Neuquen-Basin-Shales_84718 (accessed
September 20, 2011).
21.Natural Gas Americas: “First Horizontal Shale Gas Well
Completed in Argentina,” (August 19, 2011), http://
naturalgasforamerica.com/horizontal-shale-gascompleted-argentina.htm (accessed September 25, 2011).
Autumn 2011
22.Kuuskraa et al, reference 6.
23.Kuuskraa et al, reference 6.
24.Kuuskraa et al, reference 6.
25.Kuuskraa et al, reference 6.
26.Kuuskraa et al, reference 6.
27.BNK Petroleum: “BNK Petroleum Inc. Baltic Basin
Update,” (September 4, 2011), http://www.bnkpetroleum.
com/newsletters/BNK%20Press%20Release%20
Poland%20update%20Sept%204th%20final.pdf
(accessed September 5, 2011).
28.Kuuskraa et al, reference 6.
29.Sheehan J: “Europe Gears Up for the Shale Gale,”
Journal of Petroleum Technology 63, no. 7
(July 2011): 32–37.
30.Patel T: “France Vote Outlaws ‘Fracking’ Shale for
Natural Gas, Oil Extraction,” Bloomberg (July 1, 2011),
http://www.bloomberg.com/news/2011-07-01/
france-vote-outlaws-fracking-shale-for-natural-gas-oilextraction.html (accessed September 20, 2011).
31.Kuuskraa et al, reference 6.
32.Kuuskraa et al, reference 6.
35
TUNISIA
Tadla basin
MOROCCO
Ghadames
basin
Tindouf
basin
LIBYA
ALGERIA
WESTERN
SAHARA
MAURITANIA
0
Prospective basin
600
0
400
Sirte basin
Prospective area
1,200 km
800 mi
NIGER
BOTSWANA
CHAD
SWAZILAND
AFRICA
NAMIBIA
SOUTH AFRICA
Karoo basin
0
0
LESOTHO
Prospective basin
300
200
Prospective area
600 km
400 mi
> Africa shale basins. Only South Africa and northern Africa are presented because of the lack of data for much of continental Africa. (Adapted from
Kuuskraa et al, reference 6.)
The United Kingdom and Ireland are two
additional areas for shale exploration. The
United Kingdom has two major petroleum horizons—the Carboniferous northern petroleum
system and the Mesozoic southern petroleum
system.33 The two systems contain several basins
with similar depositional and tectonic history.
Government action to restrict shale exploration
activities was reversed in May 2011 and there
has recently been an increase in exploration
drilling in both systems.
Petroleum exploration has taken place in the
northern petroleum system for more than
100 years, and the Bowland Shale in the Cheshire
basin of this region holds a high potential for
development. Additional data are needed to fully
36
evaluate the resource, especially in the western
regions.34 Current estimates of GIP are on the
order of 2.7 trillion m3 [95 Tcf], of which
538 billion m3 [19 Tcf] is technically recoverable.
Recently, Cuadrilla Resources Ltd announced the
discovery of 5.7 trillion m3 [200 Tcf] of shale gas
in the Bowland Shale, which far exceeds the published estimates for the region.35
The southern petroleum system has been
explored since the 1920s, although until the discovery of the Wytch Farm field in 1973, there
were few notable finds. The Liassic shale source
rock has limited gas potential. It is deep—
averaging 4,114 m [13,500 ft]—but lacks thermal
maturity. Recoverable resource potential is only
about 28.3 billion m3 [1 Tcf]. Celtique Energie
Petroleum Ltd holds licenses in the Liassic shale
of the Weald basin. This shale is thought to
contain commercial quantities of wet gas, condensate and oil.36
Numerous other shale deposits in basins
across Europe may offer the potential for exploration and development. Most have not been widely
explored or data have not been released to the
public to evaluate their full potential.
Africa—Africa has several shale basins that
are considered potential resource plays. Because
of the presence of untapped conventional
resources, there have been few reports of gas
shale exploration activity (above). The notable
exception to this is South Africa, where major
and independent E&P companies have been
actively pursuing shale gas production.
Oilfield Review
The Karoo basin in central and southern
South Africa covers nearly two-thirds of the
country. The Permian-age Ecca shale group contains significant volumes of gas, estimated at
51.9 trillion m3 [1,834 Tcf] of GIP, of which
13.7 trillion m3 [485 Tcf] is technically recoverable.37 The shales found in this basin are characterized as highly organically rich, thermally
mature and in the dry gas window.
Several organic-rich shales are located in
basins in northern Africa—from the Western
Sahara and Morocco, across Algeria, Tunisia and
Libya—but most exploration companies are concentrating on discovering and developing conventional reservoirs in these regions. However,
unlike Algeria, Tunisia and Libya, Morocco has
few natural gas reserves and depends heavily on
imports to meet its internal consumption needs.
For this reason, exploration activity in shale
deposits is ongoing there.
The Tindouf basin (stretching across
Morocco, Western Sahara, Mauritania and western Algeria), and to a lesser extent, the Tadla
basin (in central Morocco), are targets of exploration and possible development as shale
resource plays. These Silurian-age shale deposits
contain an estimated 7.5 trillion m3 [266 Tcf] of
GIP with about 1.5 trillion m3 [53 Tcf] technically
recoverable.38 Exploration activity in Morocco,
including seismic acquisition and exploratory
drilling, recently began but is still in the early
stages. San Leon Energy plc has expressed interest in shale gas, but at present is pursuing oil
shale prospects in western Morocco.39
Except as noted above and along the west
coast of Africa, where E&P companies continue
to find, produce and develop conventional
resources, much of the remainder of Africa
remains unexplored. The dearth of existing information, along with a lack of drilling and exploration resources, provides for a poor environment
for gas shale development at present.
China—Many organic-rich shales with
promise as resource plays have been identified
in China (right). With an estimated 144.4 trillion m3 [5,101 Tcf] of GIP and 36.1 trillion m3
[1,275 Tcf] of technically recoverable gas, the
potential is comparable to that of North
America.40 There are two large sedimentary
basins of interest—the Sichuan basin in the
south and the Tarim basin in the west.
Containing thick, organic-rich shale deposits,
these basins cover large expanses and have good
reservoir characteristics for development.
Autumn 2011
Thermally mature marine shales of lower
Cambrian age (Qiongzhusi Formation) and
lower Silurian age (Longmaxi Formation) are
found in the Sichuan basin. Exploration companies have expressed considerable interest in
these formations because of gas shows in exploration wells. Their low clay content is also an
advantage, making them potentially good candidates for fracture stimulation. There is, however,
a large degree of structural complexity with
extensive folding and faulting, which introduces
risk for future development.
Operators are currently evaluating and testing
in the Sichuan basin, although no commercial production has been confirmed. However, in 2010,
China Petroleum and Chemical Corporation
(Sinopec) reportedly produced commercial quantities of gas from tests in two different parts of the
Sichuan basin—the Yuanba district in the northeast and the Fuling district in the southeast.41
The Tarim basin in western China is one of
the world’s largest frontier exploration basins.
The shales of interest are of Cambrian and
Ordovician age and served as the source rock for
the 795 million m3 [5 billion bbl] of oil equivalent
hydrocarbons in conventional carbonate reservoirs of the region. However, the arid conditions
in the region—it lies beneath the Taklimakan
Desert—mean sourcing water for fracturing will
be difficult.
The Cambrian-age shales in the Manjiaer and
Awati depressions are more than 1 km [3,280 ft]
thick, and both deposits are in the dry-gas
window. The excessive depth of these deposits
limits the net footage of accessible organic-rich
shale, but the high quality of the resource—low
clay content, dry gas, moderate TOC and good
porosity—makes them prime targets for exploration and evaluation.
MONGOLIA
KAZAKHSTAN
0
Tarim basin
Prospective basin
600
0
400
1,200 km
800 mi
CHINA
Sichuan
basin
NEPAL
INDIA
MYANMAR
> China shale basins. (Adapted from Kuuskraa et al, reference 6.)
33.Kuuskraa et al, reference 6.
34.Kuuskraa et al, reference 6.
35.Chazan G: “U.K. Gets Big Shale Find,” The Wall Street
Journal (September 22, 2011), http://online.wsj.com/
article/SB1000142405311190456390457658490413910
0880.html (accessed September 26, 2011).
36.Celtique Energie: “Central Weald—Further Data,”
http://www.celtiqueenergie.com/operations/uk/
southern_england/central_weald_data.html
(accessed September 21, 2011).
37.Kuuskraa et al, reference 6.
38.Kuuskraa et al, reference 6.
39.Petroleum Africa: “San Leon Moves Toward
Moroccan Shale Oil,” (June 28, 2011), http://www.
petroleumafrica.com/en/newsarticle.php?NewsID=
11703 (accessed September 1, 2011).
40.Kuuskraa et al, reference 6.
41.Reuters: “Sinopec Strikes Shale Gas Flow in Sichuan
Basin,” (December 23, 2010), http://www.reuters.com/
article/2010/12/23/sinopec-shale-gas-idUSTOE6BM03X
20101223 (accessed September 27, 2011).
37
Resource potentials for the Ordovician-age
shales in the Manjiaer depression are even
greater than for the Cambrian shales, with a net
thickness of 1,600 m [5,250 ft] of organic-rich
deposits. The Ordovician-age organic-rich shales
in the Awati depression are around 400 m [1,300 ft]
thick. Unfortunately, much of the resource in
both of these formations is too deep for shale
development using currently available technology. Shale exploration and evaluation activity
have not been reported for the Tarim basin.42
There are five other sedimentary basins in
China but they are nonmarine and lack thermal
maturity, although this has not prevented exploration and evaluation of their potential. Based on
early results, the five basins appear to be nonprospective for shale gas, although data continue to
be acquired and assessed.
India and Pakistan—Several basins in India
contain organic-rich shales, although only four
are viewed as having priority for exploration;
Pakistan has one basin with potential (below).
Other basins either lack thermal maturity or the
data are too limited to perform a thorough evaluation. The five basins in these countries are the
Cambay basin in western India, the KrishnaGodavari basin along the east coast of India, the
Cauvery basin in southern India, the Damodar
Valley basin in northeast India and the Southern
Indus basin in southeast Pakistan. The five basins
have a combined GIP estimate of 14 trillion m3
[496 Tcf], of which 3.2 trillion m3 [114 Tcf] is considered technically recoverable.43 Because of tectonic activity, basins in India and Pakistan are
geologically complex.
AFGHANISTAN
CHINA
PAKISTAN
Southern
Indus
basin
BHUTAN
NEPAL
Cambay
basin
INDIA
Damodar
Valley basin
BANGLADESH
MYANMAR
Krishna-Godavari
basin
Cauvery
basin
0
0
Prospective basin
600
400
1,200 km
800 mi
> India and Pakistan shale basins. (Adapted from Kuuskraa et al, reference 6.)
42.Kuuskraa et al, reference 6.
43.Kuuskraa et al, reference 6.
44.LNG World News: “India: ONGC Finds Shale Gas near
Durgapur,” (February 4, 2011), http://www.lngworldnews.
com/india-ongc-finds-shale-gas-near-durgapur/
(accessed September 11, 2011).
38
45.Kuuskraa et al, reference 6.
46.Kuuskraa et al, reference 6.
47.Tectonically stable sedimentary basins have geothermal
gradients ranging typically from 0.45°C to 0.92°C/30 m
[0.82°F to 1.65°F/100 ft].
48.Kuuskraa et al, reference 6.
The Kommugudem Shale in India’s KrishnaGodavari basin appears to have the greatest
potential for production, followed by the Cambay
Shale in the Cambay basin. Analysis of the Barren
Measure Shale in the Damodar Valley ranks it as
having the lowest potential of the four in India.
Exploration is ongoing in India with some
reported success. Although analysis indicated
marginal potential for commercial production in
the Permian-age Barren Measure Shale in the
Damodar Valley basin, it was the site of the first
shale gas well drilled in India. The 2,000 m
[6,562 ft] deep RNSG-1 well, drilled by Oil and
National Gas Corporation (ONGC) Ltd, lays claim
to being one of the first wells outside the US and
Canada to produce gas from shale in commercial
quantities.44 Additional exploratory and evaluation wells are planned for this basin.
Two organic-rich shales in the Southern Indus
basin of Pakistan are the Sembar and the Ranikot
formations. No public data on gas shale exploration or development for these formations are
available at present. Estimates based on data previously acquired are for a combined 5.8 trillion m3
[206 Tcf] of GIP, of which 1.4 trillion m3 [51 Tcf] is
technically recoverable.45
Australia—Operators in Australia have a
long history of developing unconventional reservoirs, which include tight gas and coalbed methane (CBM). Experience with CBM should be an
asset in developing gas shale resources because
the equipment and techniques used to develop
shales are similar. However, the four main basins
with shale gas potential are not located in the
same regions as the CBM fields. The main basins
being considered for development are the
Canning, Cooper (location of Australia’s main
onshore conventional production), Perth and
Maryborough basins (next page). These basins
hold an estimated 39.1 trillion m3 [1,381 Tcf] of
GIP, of which 11.2 trillion m3 [396 Tcf] is
technically recoverable.
The Ordovician-age Goldwyer Formation of
the Canning basin has, by far, the greatest estimated recoverable resource and covers the largest geographical area in Australia. This region,
however, is scarcely explored and currently lacks
infrastructure for development. There is conventional hydrocarbon production in the region,
although it is fairly recent; the first commercial
oil discovery in this basin was made in 1981. The
estimated recoverable gas is 6.5 trillion m3
[229 Tcf]; production awaits further exploration
and analysis because only 60 wells have penetrated the resource.
Oilfield Review
Canning
basin
AUSTRALIA
Maryborough
basin
Cooper
basin
Perth
basin
0
Prospective basin
800
Prospective area
1,600 km
0
500
1,000 mi
> Australia shale basins. (Adapted from Kuuskraa et al, reference 6.)
As Australia’s main onshore gas supply, the
Cooper basin produces about 14 million m3/d
[0.5 Bcf/d] of natural gas from conventional
and low-permeability reservoirs. The lowpermeability, tight gas reservoirs are usually
hydraulically fractured for production. Because
of this, the Cooper basin has personnel with
expertise and hydraulic fracturing equipment for
developing shale resources.46
The Permian-age Roseneath and Murteree
shales of the Cooper basin appear favorable for
development. They vary from about 50 to 100 m
[165 to 330 ft] in thickness. A third formation in
the basin, the Epsilon, is primarily a mixture of
sandstone with carbonaceous shale and coal. The
three targets are often viewed in combination
and referred to as the REM formations.
Although their lacustrine origin and Type III
kerogen source material are not typically the
target of gas shale development, the REM
formations have some positive attributes. Their
low clay content results in rocks that can be more
easily hydraulically fractured. In addition, an
extremely high geothermal gradient—1.4°C/30 m
[2.55°F/100 ft] in general, and up to 1.9°C/30 m
[3.42°F/100 ft] in some parts—accelerated maturation of the source rock.47
Autumn 2011
Although operators are still in the early stages
of exploration, they are actively evaluating and
testing in the Cooper basin. At least one exploration well has been drilled in the basin and an
E&P company is analyzing the core for gas content and mechanical properties. Santos Energy
Ltd and Beach Energy Ltd are two of the most
active companies in gas shale exploration there.
The Perth basin is relatively small. The
onshore portion of the basin has marine sediments with production potential, although much
of the interval of interest is too deep for gas shale
development. Formations in the northern extent
of the Dandaragan trough, a large syncline of
Silurian to Cretaceous age, contain potential
resource rock. With high geothermal gradients
and moderate to high TOCs, younger marine sediments, such as the Permian-age Carynginia and
Kockatea shales, offer promise as well.48
The Maryborough basin is on the east coast of
Australia. There is no conventional hydrocarbon
production in the region and little data for evaluating its potential. With data from only five exploration wells, more information is needed to
fully characterize the shale potential. However,
the Cretaceous Maryborough Formation, a thick
marine deposit, does show promise. Recent
estimates suggest a possible 651 billion m3
[23 Tcf] of technically recoverable gas with the
possibility of adding to the estimate when the
unexplored and poorly understood southern half
of the basin is included in the evaluation.
Other exploration activities are taking place
throughout the world. Some regions, such as the
Middle East and Russia, have abundant gas shale
potential, but easy access to conventional reservoirs precludes serious development efforts of
shale. Energy-hungry and often resource-poor
countries constitute the majority of the ongoing
exploration activity.
Moving Forward
Energy resources are the lifeblood of modern
economies. Twenty years ago, dire warnings were
issued in the US that natural gas supplies were
dwindling and alternate sources of supplies were
needed—quickly. An aggressive program was recommended for importing LNG from countries
with accessible supplies. Today, the situation is
remarkably different. The US has an abundance
of natural gas and the long-term supply is more
secure than ever because operators have learned
to tap natural gas from unconventional resource
plays—primarily shale, but also CBM. Operators
in many regions of the world, having observed the
success in North America, are moving to catch up.
At one time, drilling and reservoir engineers
may have considered shales nuisances to deal
with in the search of reservoir quality rocks, and
the thought of commercial production of natural
gas from shale deposits was simply not realistic.
But the oil and gas industry continues to develop
new techniques and create ways to access hydrocarbons. As the global revolution in gas shale
development gains momentum, exploration companies have only just begun to uncover what
organic shales have to offer.
—TS
39