shale gas: a global resource -...
TRANSCRIPT
28 Oilfield Review
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 BoyerPittsburgh, Pennsylvania, USA
Bill ClarkOklahoma City, Oklahoma, USA
Valerie JochenCollege Station, Texas, USA
Rick LewisCamron K. MillerDallas, Texas
Oilfield Review Autumn 2011: 23, no. 3. Copyright © 2011 Schlumberger.
Shales are the most abundant form of sedimen-tary rock on Earth. They serve as the source rocks for hydrocarbons migrating into perme-able 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 pro-duced. Finding and producing gas from shale formations, initially a North American phenom-enon, 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 technolo-gies—fracture stimulation and horizontal drill-ing—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 ResourcesOrganic-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, uncon-ventional gas reservoirs are those that can be pro-duced neither at economic flow rates nor in economic volumes unless the well is stimulated by hydraulic fracture treatment or accessed by a hori-zontal 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 hydrocar-bons. Unlike conventional plays, resource plays cover a wide areal extent and are not typically con-fined to geologic structure.
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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 prac-tices. Operators drilled vertical wells that pro-duced 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 exclu-sively 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 signifi-cantly 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-of- the-top-5-us-gas-shales/ (accessed October 17, 2011).
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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.
Global PerspectivesE&P companies have routinely produced hydro-carbons 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 situ-ation may change rapidly. Gas shale exploration is ongoing in South America, Africa, Australia, Europe and Asia. Around the world, E&P compa-nies are acquiring and analyzing seismic data, drilling exploratory wells and evaluating forma-tions for gas production capabilities. As assess-ment of global shale resources has continued, estimates for resource potential have gone up dramatically (next page, top). A recent study esti-mated that the global natural gas resource poten-tial 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 acre age positions in Europe include ExxonMobil Corporation, Total S.A., ConocoPhillips Company and Marathon Company. With limited experience in shale exploration and development, these com-panies are partnering with companies that devel-oped 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 experi-ence, 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.
> 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.)
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
5.0
201020092008200720062005Year
Annu
al s
hale
gas
pro
duct
ion,
Tcf
20042003200220012000
Eagle Ford Shale
Marcellus Shale
Haynesville-Bossier Shale
Woodford Shale
Fayetteville Shale
Barnett Shale
Antrim Shale
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).
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Autumn 2011 31
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 land-owners, 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 game-changing 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.
Shale Gas AssessmentsUnited 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
> 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.]
Region 1997 Rogner Study, Tcf 2011 EIA Study, Tcf
North America
South America
Europe
Africa
Asia
Australia
Other
Total
3,842
2,117
549
1,548
3,528
2,313
2,215
16,112
7,140
4,569
2,587
3,962
5,661
1,381
25,300
Not available
> 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.)
Established basins with resource estimate
Potential basins withoutresource estimate
Countries withunknown potential
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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 develop-ment. When US plays are ranked instead by esti-mates of original gas in place (GIP), the Marcellus Shale at 42.5 trillion m3 [1,500 Tcf]
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 cur-rently in production. Some of the more notable are the Fayetteville, Woodford, Antrim, Eagle Ford and New Albany shales.
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
>North America shale plays. (Adapted from Kuuskraa et al, reference 6.)
Bakken***
Barnett
Eagle Ford
Burgos basin
Tampico basin
Tuxpan basin
Veracruz basin
Pearsall
Haynesville-Bossier
Marcellus
Lower BesaRiver
MontneyDeep basin
DoigPhosphate
Horn River, Cordovaand Laird basins
Colorado Group
Utica
Utica
Horton Bluff
Monterey-Temblor
Monterey
Niobrara*
Mowry
Tuscaloosa
Niobrara*
Cody
Hilliard-Baxter-Mancos-Niobrara
Mancos
Avalon
Barnett-Woodford
Hermosa
Floyd-Neal
Chattanooga
Conasauga
Lewis
Pierre-Niobrara Excello-Mulky
Antrim
NewAlbany
Gammon
Bend
Heath**
FrederickBrook
Pimienta,Tamaulipas
Eagle Ford,La Casita
Sabinas basin
Eagle Ford,Tithonian
Maltrata
Woodford
Fayetteville
New Caney
Muskwa, Otter Park,Evie and Klua shales
Current shale playsProspective shale playsBasins
Stacked playsShallowest or youngestIntermediate depth or ageDeepest or oldestMixed shale and chalk playMixed shale and limestone playMixed shale and tight dolostone-siltstone-sandstone play
***
***
CANADA
USA
MEXICO
0 600 1,200 km
0 400 800 mi
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Muskwa, Otter Park, Evie, Klua and lower Besa River shales. Several operators have been active in these areas with positive results. The Triassic-age 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 techni-cally 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 esti-mated 56.6 billion m3 [2 Tcf] is technically recov-erable. 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 north-east 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
67 trillion m3 [2,366 Tcf] of GIP, of which 19.3 trillion m3 [681 Tcf] is judged to be techni-cally 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 reser-voirs 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 com-menced in May of 2011 with a rate of approxi-mately 84,000 m3/d [3.0 MMcf/d]. Pemex plans to drill 20 additional wells in the near future to fur-ther 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 poten-tial, with an estimated 77 trillion m3 [2,732 Tcf] of GIP, of which 21.9 trillion m3 [774 Tcf] is consid-ered technically recoverable.18 Brazil follows with
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.
> South America shale basins. (Adapted from Kuuskraa et al, reference 6.)
SOUTH AMERICA
0 500 1,000 km
0 300 600 mi
Paraná basin
Chaco basin
Neuquénbasin
San Jorgebasin
Austral-Magallanesbasin
Prospective basin
CHILEARGENTINA URUGUAY
PARAGUAY
BRAZILBOLIVIA
PERU
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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 lim-ited 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 con-ventional 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 over-pressured 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 sec-tions 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 pre-dominant 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 pro-duction. It is found at depths between 3,487 and 3,706 m [11,440 and 12,160 ft]. The lacus-trine depositional environment of these sedi-ments poses a potential risk for development because lacustrine shales are viewed as gener-ally 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 indi-cates moderate TOC values and good thermal
maturity. The best prospects for gas shale devel-opments 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 pro-duction. 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, encom-passing 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 depos-its. 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 matu-rity 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 explora-tion in Europe. The Silurian-age Baltic and Lublin basins run north-central to southeast across the country and are bounded by the Trans-European 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 fault-ing. Estimated gas in place for these three basins is 22.4 trillion m3 [792 Tcf] GIP, of which 5.3 tril-lion m3 [187 Tcf] is considered technically recov-erable.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 poten-tial. 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, thick-nesses 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 win-dow. Because it was once deeper but uplifted along its western margin, the Liassic shale is gen-erally 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, pend-ing 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 via-bility of resource plays is difficult to realize.
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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
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] recover-able.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 pro-duction; however, data are sparse. Based on avail-able data, the estimated GIP is 16.7 trillion m3
[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 geo-thermal gradient, which has accelerated matura-tion 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.
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-gas-completed-argentina.htm (accessed September 25, 2011).
> Europe shale basins. (Adapted from Kuuskraa et al, reference 6.)
0 750 1,500 km
0 500 1,000 mi
Prospective basin Prospective area
SPAIN
FRANCE
PORTUGAL
UK
IRELAND
GERMANY
NORWAY
SWEDEN
DENMARK
BELGIUM
THENETHERLANDS
RUSSIA
ESTONIA
LATVIA
LITHUANIA
POLAND
CZECHREP.
BELARUS
UKRAINE
ROMANIA
MOLDAVIA
BULGARIA
SERBIA
HUNGARY
CROATIA BOSNIA& HER.
SLOVAKIA
AUSTRIA
TURKEYGREECE
ALBANIAMACEDONIA
ITALY
Parisbasin
Weald basin
Balticbasin
Podlasiebasin
Lublinbasin
Southeastbasin
Aquitanebasin
Northernpetroleumsystem
Southernpetroleumsystem
Ebrobasin
Po basin
Molassebasin Vienna basin
Lusitanian-Penichebasin
North Sea–German basin
Alum Shale
Carpathian-Balkanianbasin
Pannonian–Transylvanianbasin
Trans-Europeanfault
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%20Poland%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-oil-extraction.html (accessed September 20, 2011).
31. Kuuskraa et al, reference 6. 32. Kuuskraa et al, reference 6.
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36 Oilfield Review
The United Kingdom and Ireland are two additional areas for shale exploration. The United Kingdom has two major petroleum hori-zons—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
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 pub-lished estimates for the region.35
The southern petroleum system has been explored since the 1920s, although until the dis-covery 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, con-densate and oil.36
Numerous other shale deposits in basins across Europe may offer the potential for explora-tion 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.
> 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.)
0 300 600 km
0 200 400 mi
Prospective basin Prospective area
SOUTH AFRICA
BOTSWANA
NAMIBIA
LESOTHO
SWAZILAND
Karoo basin
Ghadamesbasin
Sirte basin
Tadla basin
Tindoufbasin
NIGER CHAD
LIBYAALGERIA
MAURITANIA
WESTERNSAHARA
MOROCCO
TUNISIA
Prospective basin Prospective area0 600 1,200 km
0 400 800 mi
AFRICA
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Autumn 2011 37
The Karoo basin in central and southern South Africa covers nearly two-thirds of the country. The Permian-age Ecca shale group con-tains 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 recover-able.37 The shales found in this basin are charac-terized 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 con-centrating on discovering and developing con-ventional 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 west-ern Algeria), and to a lesser extent, the Tadla basin (in central Morocco), are targets of explo-ration 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 inter-est 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 infor-mation, along with a lack of drilling and explora-tion 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 tril-lion 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.
Thermally mature marine shales of lower Cambrian age (Qiongzhusi Formation) and lower Silurian age (Longmaxi Formation) are found in the Sichuan basin. Exploration compa-nies have expressed considerable interest in these formations because of gas shows in explo-ration wells. Their low clay content is also an advantage, making them potentially good candi-dates 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 pro-duction has been confirmed. However, in 2010, China Petroleum and Chemical Corporation (Sinopec) reportedly produced commercial quan-tities of gas from tests in two different parts of the Sichuan basin—the Yuanba district in the north-east 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 reser-voirs 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 explora-tion and evaluation.
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).
> China shale basins. (Adapted from Kuuskraa et al, reference 6.)
MONGOLIA
CHINA
MYANMAR
NEPAL
INDIA
KAZAKHSTAN
0 600 1,200 km
0 400 800 mi
Prospective basin
Tarim basin
Sichuanbasin
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).
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38 Oilfield Review
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 technol-ogy. 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 explo-ration and evaluation of their potential. Based on early results, the five basins appear to be nonpro-spective 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 evalu-ation. The five basins in these countries are the Cambay basin in western India, the Krishna-Godavari 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 con-sidered technically recoverable.43 Because of tec-tonic activity, basins in India and Pakistan are geologically complex.
The Kommugudem Shale in India’s Krishna-Godavari 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 evalua-tion 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 explora-tion or development for these formations are available at present. Estimates based on data pre-viously 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 reser-voirs, which include tight gas and coalbed meth-ane (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 esti-mated recoverable resource and covers the larg-est geographical area in Australia. This region, however, is scarcely explored and currently lacks infrastructure for development. There is conven-tional 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 pene-trated the resource.
> India and Pakistan shale basins. (Adapted from Kuuskraa et al, reference 6.)
Prospective basin0 600 1,200 km
0 400 800 mi
Krishna-Godavaribasin
Cauverybasin
Cambaybasin
SouthernIndusbasin
Damodar Valley basin
INDIA
PAKISTAN
AFGHANISTAN
CHINA
NEPALBHUTAN
MYANMARBANGLADESH
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).
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.
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Autumn 2011 39
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 low- permeability, 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 mat-uration of the source rock.47
Although operators are still in the early stages of exploration, they are actively evaluating and testing in the Cooper basin. At least one explora-tion well has been drilled in the basin and an E&P company is analyzing the core for gas con-tent 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 sedi-ments 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 sedi-ments, 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 evalu-ating its potential. With data from only five explo-ration 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 reser-voirs precludes serious development efforts of shale. Energy-hungry and often resource-poor countries constitute the majority of the ongoing exploration activity.
Moving ForwardEnergy 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 rec-ommended 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 hydro-carbons. As the global revolution in gas shale development gains momentum, exploration com-panies have only just begun to uncover what organic shales have to offer. —TS
> Australia shale basins. (Adapted from Kuuskraa et al, reference 6.)
AUSTRALIA
Perthbasin
Canningbasin
Cooperbasin
Maryboroughbasin
0 800 1,600 km
0 500 1,000 mi
Prospective basin Prospective area
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