1.1 Introduction
The United States Energy Information Administration (EIA) comprehensively assessed global shale reserves in 2011 and followed up in 2013 (U.S. Energy Information Administration 2015). The 2011 assessment focused on 14 regions outside the United States, and the 2013 assessment expanded to 137 formations in 95 basins from 41 countries (Table 1.1). The EIA estimates the global shale gas reserves at 7,577 Tcf and the global shale oil reserves at 419 billion bbl. The 10 largest reserves for shale gas are China (1,115 Tcf), Argentina (802 Tcf), Algeria (707 Tcf), United States (623 Tcf), Canada (573 Tcf), Mexico (545 Tcf), Australia (437 Tcf), South Africa (370 Tcf), Russia (285 Tcf), and Brazil (245 Tcf). The European Union combined has significant reserves (435 Tcf), with Poland (146 Tcf) and France (137 Tcf) having the largest reserves. The 10 largest reserves for shale oil are United States (78 Bbbl), Russia (75 Bbbl), China (32 Bbbl), Argentina (27 Bbbl), Libya (26 Bbbl), United Arab Emirates (23 Bbbl), Chad (16 Bbbl), Australia (17.5 Bbbl), Venezuela (13 Bbbl), and Mexico (13 Bbbl). To date, only the United States and Canada have reached commercial level production for shale gas and oil, followed to a lesser extent by China and Argentina. While the estimated ultimate recovery (EUR) of these resources may be significant, the current status of their development relies on several factors. These factors include whether the reserves are technically and economically recoverable (i.e., readily accessible geographically and geologically), the status of existing infrastructure, such as refining capacity and pipelines, and a favorability of regulatory frameworks and political climate. The Society of Petroleum Engineers (SPE) defines proved reserves as those that are commercially recoverable “under current economic conditions, operating methods, and government regulations” (SPE 1997). The EIA did not consider other low permeability tight formations, such as sandstones and carbonates, and only assessed those with sufficiently studied geology (EIA 2013). It also considered the current technology available for the development of these formations, including the advances in drilling and hydraulic fracturing technology (Stolz and Griffin, see Chapter 2). The EIA calculated three values: OIP/GIP concentration, Risked OIP/GIP, and Risked Recoverable (EIA 2013). Oil-in-place (OIP) and gas-in-place (GIP) estimates were based primarily on the thickness of the organic-rich shale, porosity, pressure, and temperature. Risked OIP/GIP estimates were based on two additional factors: the play success probability (how likely is the play to produce) and the prospective area success factor (which includes additional risk factors that may affect production). Risk Recoverable, or the estimated technically recoverable oil and gas, was calculated by multiplying the OIP or GIP value by a recovery efficiency factor (EIA 2013). The latter factor was based on the mineralogy of the shale and how efficiently the formation could be hydraulically fractured. Only the data for Risked Recoverable estimates are included here, as they provide a baseline for assessing how successful a play might be (EIA 2013). This chapter provides a brief review of the major shale gas and oil plays and the status of their development as of 2020, focusing on China, Argentina, Algeria, the United States, Canada, Mexico, Australia, South Africa, Russia, and Brazil. Additional discussions can be found in the chapters covering the United States (Stolz and Griffin, see Chapter 2; Graham and Rupp, see Chapter 4), Australia (McCarron and Doughal, see Chapter 3), and France and the United Kingdom (Graham and Rupp, see Chapter 4).
Table 1.1. Global distribution of tight oil and gas reserves and the current status of development (US EIA 2015a)
1) Herrera (Reference Herrera2020), 2) Mead and Maloney (Reference Mead and Maloney2018a), 3) Mead and Maloney (Reference Mead and Maloney2018b), 4)Vinson and Elkins (Reference Vinson and Elkins2020), 5) Bertram (Reference Bertram2019), 6) Dias (Reference Dias2019), 7) Kuznestsov (Reference Kuznestsov2013), 8) Reed (Reference Reed2015), 9) Stefan (Reference Stefan2015), 10) Rapoza (Reference Rapoza2019), 11) Thomas (Reference Thomas2014), 12) BBC News (2012), 13) Ambrose (Reference Ambrose2019), 14) Cairney et al. (Reference Cairney, Fischer and Ingold2018), 15) Gesley (Reference Gesley2017), 16) Aczel (Reference Aczel2020), 17) Chikhi et al. (Reference Chikhi, Zhdannikov and Bousso2019), 18) Reuters (2014), 19) Gasser (Reference Gasser2017), 20) Myers (Reference Myers2019), 21) Campbell (Reference Campbell2013), 22) Yadav (Reference Yadav2020).
1.2 China
China has seven areas that have been assessed for technically recoverable oil and gas, namely the Sichuan, Tarim, Junggar, Songliao, Jianghan, and Subei basins, and the Yangtze Platform (US EIA 2015e). The Sichuan (626 Tcf), Tarim (216 Tcf), Junggar (36 Tcf), and Songliao (16 Tcf) basins have the greatest potential for shale gas. The major shale oil reserves are found in the Junggar, Tarim, and Songliao basins with an estimated 8 Bbbl, 12 Bbbl, and 11.5 Bbbl, respectively. South China has marine black shales, with major development in the Sichuan Basin and Yangtze Platform. Commercial exploration and production has been underway, reportedly reaching nearly 600 wells and 9 bcm of production in 2017 (Vinson and Elkins Reference Vinson and Elkins2020). The expansion has been driven by the 13th Five-Year-Plan for Energy Development announced by the National Development and Reform Commission and National Energy Administration in early 2017 with the goal of increasing proven reserves to 1 tcm by 2020 (Vinson and Elkins Reference Vinson and Elkins2020). The geological complexity of the basins, with their faults and seismic activity, has proven to be a challenge. Development in Sichuan has been hampered by earthquakes (Myers Reference Myers2019). Other challenges include the extreme depth of the deposits (3,200 m on average), limited accessibility, the lack of water resources, limited geologic data, clay-rich deposits that are more difficult to hydraulically fracture, lack of pipelines in some areas, and the high cost of development (US EIA 2015e). China has made investments in other global shale plays such as the United States in an effort to gain greater expertise. Sinopec is the major oil and gas company involved in the development, as many of the foreign companies such as Shell, Chevron, and BP have dropped out. China has also created its own oilfield services industry, manufacturing the equipment required for shale gas and oil extraction (Vinson and Elkins Reference Vinson and Elkins2020).
1.3 Argentina
Argentina, traditionally known for its oil production, has four basins, the Neuquén, Golfo San Jorge, Austral, and Paraná (US EIA 2015c). Together, they are estimated to contain 802 Tcf and 27 Bbbl of risked recoverable gas and oil. The Neuquén is a marine shale, Jurassic to Cretaceous in age. The Golfo San Jorge is a lacustrine shale, Jurassic to Cretaceous in age. The Austral basin is a marine black shale, Cretaceous in age, while the Paraná is a black shale of Devonian age (US EIA 2015c). The Neuquén is the most promising for development with commercial production by the Argentine national company YPF SA, as well as foreign companies Apache, EOG Resources, ExxonMobil, and TOTAL. Development for shale oil began in the Vaca Muerta formation in 2010 (US EIA 2015c). The industry, as a whole, has expanded since then with the passage of key legislation. The Hydrocarbon Sovereignty Law, passed in 2012 and enacted by an Executive Branch decree, reclaimed the country’s hydrocarbon deposits by public domain (Beller and Schiariti Reference Beller and Schiariti2012). The law also declared a 51% share of YPF SA and Respol YPF Gas SA, essentially repatriating the companies after several years of private ownership. Further stimulation was provided by the recently decreed “Argentine Natural Gas Production and Demand Scheme Promotion Plan,” also known as the 2020–2024 Gas Plan. The plan set production goals for the Austral (20 MMm3/d) and Neuquén (47.2 MMm3/d) basins. It has reinvigorated the operations of the regional private companies Tecpetrol SA and Pluspetrol SA. The main challenge limiting development has been financing, as the country continues to suffer from high inflation and interest rates (Newberry Reference Newbery2019). The high cost of drilling and completion also contributes as it continues to be greater than the price break point (Newbery Reference Newbery2019). An emerging issue has been social unrest in response to the rapid inflation and the country’s response to COVID-19, with oilfield workers striking and healthcare providers (i.e., nurses, doctors, orderlies) blockading roads in protesting for better pay and health benefits (Otaola Reference Otaola2021).
1.4 Algeria
The geologic history of Algeria has created a patchwork of seven different basins scattered across the country. From west to east, they are the Tindouf, Reggane, Timimoun, Ahnet, Mouydir, Illizi, and Ghadames/Berkine basins. Together, they are estimated to contain 707 Tcf and 5.7 Bbbl of risked recoverable gas and oil, respectively. There are two major shale gas and oil formations in Algeria, the Tannezuft shale (Silurian) and the Frasnian shale (Upper Devonian) within these basins (US EIA 2015b). Exploratory drilling occurred in the Ahnet basin near In Salah in late 2014 (Belakhdar Reference Belakhdar2020). Despite Algeria’s reliance on petroleum exports for their economy, the development of Algerian shales has been met with public protests (Chikhi et al. Reference Chikhi, Zhdannikov and Bousso2019; Belakhdar Reference Belakhdar2020) and political unrest (Aczel et al. Reference Aczel, Makuch and Chibane2018; Aczel Reference Aczel2020). The National Assembly passed legislation in 2013 to promote shale gas and later actively sought international partners for their development. This resulted, however, in large protests held in the cities of Adrar and Ouargla in 2014 and 2015. There was again political unrest after the 2019 Hydrocarbon Law was passed to encourage development and international support. Further development is on hold (Aczel Reference Aczel2020).
1.5 United States
The United States has several large shale deposits, with more than 24 basins and 38 formations (US EAI 2020; Stolz and Griffin Reference Stolz, Griffin, Stolz, Griffin and Bain2021, see Table 2.1). Alabama, Alaska, Arkansas, California, Colorado, Indiana, Kansas, Louisiana, Michigan, Mississippi, Montana, Nebraska, Nevada, New Mexico, North Dakota, Ohio, Oklahoma, Pennsylvania, Tennessee, Texas, Utah, Virginia, West Virginia, and Wyoming all have deposits that are being or could be developed (see map in Chapter 2, Figure 2.1). Most of the shale oil is being produced from seven shale basins, namely, the Permian Basin (Texas), Eagle Ford (Upper Cretaceous) in Texas, Bakken (Upper Devonian) in North Dakota and Montana, Niobrara (Upper Cretaceous) in Colorado and Wyoming, Haynesville (Jurassic) in Louisiana and Texas, and the Utica (Ordovician) and Marcellus (Devonian) both in Pennsylvania, Ohio, and West Virginia (US EIA 2020). While fracking is permitted and there are sizable shale deposits in Alaska (Gryc Reference Gryc1985), the focus has been exclusively on conventional reserves. Greater discussion of unconventional oil and gas extraction in the United States can be found in Chapter 2.
Three states currently ban hydraulic fracturing, Maryland, New York, and Vermont. Other bans or moratoria exist at the city or county level. Attempts to ban fracking in Denton and Dallas, Texas, were overturned by the state legislature (Chapter 4). In Pennsylvania, Pittsburgh City Council passed an ordinance prohibiting the commercial extraction of natural gas in 2010 (Baca Reference Baca2010). Subsequently, Bucks and Monroe County councils passed similar ordinances. None have been challenged to date. Most recently, the Delaware River Basin Commission made their moratorium permanent. In additional to Pennsylvania, the Delaware River Basin covers parts of New York, New Jersey, and Delaware (E360 Digest 2021). In California, fracking is banned in Los Angeles and Santa Cruz, as well as San Benito and Monterey counties.
1.6 Canada
Canada has numerous basins and formations across British Columbia and the Northwest Territories, Alberta, Saskatchewan and Manitoba, Quebec, and Nova Scotia (US EIA 2015g). Together, they are estimated to contain 573 Tcf and 8.8 Bbbl of risked recoverable gas and oil, respectively. The bulk of the deposits are in Western Canada, primarily British Columbia and Alberta (Figure 1.1), and include the Liard Basin, Horn River Basin, Cordova Embayment, Alberta, and Deep Basin (Table 1.1). Major formations are the Muskwa (Upper Devonian) and Otter Park (Upper Devonian), both of which are found in the Horn River Basin and Cordova, and the Lower Besa River (Devonian) in the Liard Basin (US EIA 2015g). The Williston Basin, with the Bakken formation (Upper Devonian), is in southern Saskatchewan and Manitoba. Moving east, Quebec is home to the Appalachian Fold Belt and the Utica shale (Ordovician). The Windsor Basin, with the Horton Bluff formation (Mississippian), is in Nova Scotia (Table 1.1).
Shale development is occurring in six provinces, Alberta, British Columbia, Manitoba, Northwest Territories, Saskatchewan, and Yukon, with over 200,000 unconventional wells having been drilled. Moratoria are under effect in three provinces, Newfoundland, Nova Scotia, and Quebec. New Brunswick initially had a moratorium in 2015, which converted to a ban in 2018. Both Prince Edward Island and Ontario have not considered a moratorium as neither have reserves that could be developed (Natural Resources Canada 2020). The two major hurdles to development in Canada have been public concerns over the environmental impacts (e.g., drinking water contamination, induced earthquakes, landscape impacts) and lack of economically viable deposits (Minkow Reference Minkow2017).
1.7 Mexico
The major basins and deposits of Mexico lie on its eastern side along the Gulf of Mexico. The five major basins, which are all marine in origin, are the Burgos, Sabinas, Tampico, Tuxpan, and Veracruz (US EIA 2015h). They are estimated to contain 545 Tcf of risked recoverable gas and 13.1 Bbbl of combined oil and condensate. The major formations are the Eagle Ford (Upper Cretaceous) and Tithonian (Upper Jurassic) of the Burgos and Sabinas basins, Pimienta (Jurassic) in the Tampico basin, Tamaulipas (Middle Cretaceous) in the Tuxpan basin, and Maltrata (Upper Cretaceous) in the Veracruz basin (US EIA 2015h). Petroleos Mexicano SA de CV (Pemex), the state-owned petroleum company, began exploration in 2011, with a test well in the Eagle Ford Shale. The geologic complexity (i.e., deformities) and extreme depths (>5 km) of some of the shale deposits as well as lack of geophysical data have hampered further development. Economic pressures have also contributed, with the high cost of oil field services in Mexico and the lack of foreign investment (Vinson and Elkins Reference Vinson and Elkins2020). Concerns over infrastructure security (i.e., safety of the pipelines) and water availability are also in play. While initially promoting the development of their oil and gas reserves with a goal of energy independence, President Andrés Manuel López Obrador is considering a ban on hydraulic fracturing, a move supported by Environment Minister Victor Toledo (NGI 2019).
1.8 Australia
There have been six assessed shale gas basins in Australia, the Cooper, Canning, Georgina, Beetaloo, Perth, and Maryborough (US EIA 2015d). Together, they are estimated to contain 437 Tcf and 17.5 Bbbl of risked recoverable gas and oil, respectively. The Cooper Basin contains lacustrine deposits including the Roseneath, Epsilon, and Murteree shales, which are all Permian in age (Guo and Mccabe Reference Guo and Mccabe2017). The hydrocarbons have been concentrated in three troughs, the Nappamerri, Patchawarra, and Tenappera (US EIA 2015d). The Canning basin in northwestern Australia, is the largest in area (469,000 km2) and contains the Goldwyn shale (Middle Ordovician). The Georgina basin, with the Dulcie and Toko Troughs of the L. Arthur shale (Middle Cambrian), is the next in areal extent (324,000 km2). The Perth, Beetaloo, and Maryborough basins are significantly smaller (52,000, 36,000, and 11,000 km2, respectively). The M. Velkerri shale and L. Kyalia shale of the Beetaloo basin are the oldest, and are both Precambrian in age. The Perth basin has the Kockatea shale (Late Triassic), while the small Maryborough has the Goodwood/Cherwell mudstone (Cretaceous) (Table 1.1).
Development in Australia varies by province, with active development, moratoria, or bans (Chapter 3). Queensland has been the most active, with major infrastructure already existing. New South Wales allows it, and the Northern Territory is mixed, with 51% open to development. Western Australia does not permit unconventional development, with the exception of existing leases, and the landowners maintain the right of refusal. Victoria has completely banned all onshore unconventional gas development, South Australia has a 10-year ban, and the Tasmanian Government has a moratorium until 2025. Further discussion about Australia can be found in Chapter 3.
1.9 South Africa
South Africa has one major basin, the Karoo, but it covers two-thirds of the country (612,000 km2). The Karoo basin has three marine shale deposits, the Prince Albert, Whitehill, and Collingham, all Late Permian in age (US EIA 2015j). Together, they are estimated to contain 370 Tcf of risked recoverable gas. The southern portion of the basin has promise for dry gas production, especially the Whitehill formation with its high organic content (6%). The formations have been impacted by past geologic activity in the form of igneous intrusions, which may have affected the quantity and quality, as well as the ability to extract the gas (US EIA 2015j). Economic and energy needs have influenced the country’s views on fracking. Most of South Africa’s energy is generated from coal. Initially, there was a moratorium, enacted in 2011, on oil and gas exploration in the Karoo Basin, primarily as a result of environmental concerns and water scarcity (Agbroko Reference Agbroko2011). The moratorium was lifted in 2012 after the release of the findings of an inter-agency task force, and in 2017 the Mineral Resources Minister issued guidelines regulating permits (Vinson and Elkins Reference Vinson and Elkins2020). The Supreme Court of Appeal of South Africa subsequently decided in 2019 that the permits issued by Ministry of Mines were not legal. More significant barriers to further development include the lack of technical expertise, limited infrastructure, continued environmental and water scarcity concerns, as well as growing public opposition (Vinson and Elkins Reference Vinson and Elkins2020).
1.10 Russia
Although Russia has several basins with potential, namely the Timan Pechora, Volga-Urals in the west, and East Siberia in the east, only the centrally located West Siberia Basin has been assessed (US EIA 2015i). In an area that has been a major source of conventional oil and gas since the 1960s, the Central and North Bazhenov shales (Upper Jurassic) of the West Siberia Basin (3.5 million km2) could potentially hold 75 bbl of oil and 285 tcf of gas (US EIA 2015i). Gazprom Neft successfully drilled a horizontal well in the Bazhenov, demonstrating that Russia was fully capable of unconventional extraction; however, further development has been hampered by political pressures, both foreign and domestic (Rapoza Reference Rapoza2019). A major deal between Exxon and the Russian oil producer Rosnef was tabled owing to sanctions imposed by the United States after the Ukraine incursion. More significant is President Vladimir Putin’s insistence that Russia does not need to tap unconventional resources as the country has enough conventional resources (Rapoza Reference Rapoza2019).
1.11 Brazil
Brazil boasts 18 onshore basins, with 3, the Paraná (Devonian), Solimões (Devonian), and Amazonas (Devonian), providing the bulk of conventional oil and gas (US EIA 2015f). In combination these marine black shales may hold 245 Tcf and 5.4 bbl of risked recoverable gas and oil (US EIA 2015f). Other basins that have not been fully characterized are the Parnaiba, Parecis, Sao Francisco, and Chaco-Parana, which have significant areal extent, as well as the smaller coastal locations of Potiguar, Sergipe- Alagoas, Taubate, and Reconcavo. Unconventional development is allowed in Brazil; however, it has been banned in the states of Paraná and Santa Catarina. When the government auctioned off land in the Jurua Valley for development, the court voided the sales in defense of the indigenous inhabitants, protecting their ancestral territory (Rogato Reference Rogato2016). In February 2020, Brazil’s energy ministry formed an agreement with the US Department of Energy to increase investment and provide technical support for the development of Brazilian unconventional reserves (Bnamericas 2020).
1.12 Conclusions
The reserves for tight oil and gas shales are indeed global, with formations known in six continents (Antarctica the sole exception). Based on US EIA assessments, many of these reserves are significant. As has been discussed here, their successful development, however, is dependent on many factors, including the ease of accessibility and feasibility of extraction (i.e., technically recoverable), technical expertise, infrastructure, supporting service industry, financing, government regulations, environmental concerns, and public sentiment.
