oleocene.org

Why Canada is the next frontier for shale oil

Nia Williams JANUARY 29, 2018
CALGARY, Alberta (Reuters)

The revolution in U.S. shale oil has battered Canada’s energy industry in recent years, ending two decades of rapid expansion and job creation in the nation’s vast oil sands.

Now Canada is looking to its own shale fields to repair the economic damage.

Canadian producers and global oil majors are increasingly exploring the Duvernay and Montney formations, which they say could rival the most prolific U.S. shale fields.

Canada is the first country outside the United States to see large-scale development of shale resources, which already account for 8 percent of total Canadian oil output. China, Russia and Argentina also have ample shale reserves but have yet to overcome the obstacles to full commercial development.

Canada, by contrast, offers many of the same advantages that allowed oil firms to launch the shale revolution in the United States: numerous private energy firms with appetite for risk; deep capital markets; infrastructure to transport oil; low population in regions that contain shale reserves; and plentiful water to pump into shale wells.

Together, the Duvernay and Montney formations in Canada hold marketable resources estimated at 500 trillion cubic feet of natural gas, 20 billion barrels of natural gas liquids and 4.5 billion barrels of oil, according to the National Energy Board, a Canadian regulator.

“The Montney is thought to have about half the recoverable resources of the whole oil sands region, so it’s formidable,” Marty Proctor, chief executive of Calgary-based Seven Generations Energy, told Reuters in an interview.

Canada’s shale output stands at about 335,000 bpd, according to energy consultants Wood Mackenzie, which forecasts output should grow to 420,000 bpd in a decade. The pace of output growth could quicken and the estimated size of the resources could rise as activity picks up and knowledge of the fields improves, according to the Canadian Association of Petroleum Producers.

Seven Generations and Encana Corp, also based in Calgary, are among leading producers developing the two regions. Global majors including Royal Dutch Shell and ConocoPhillips - who pulled back from the oil sands last year - are also developing Canadian shale assets.

Chevron Corp announced its first ever Canadian shale development in the Duvernay in November. Spokesman Leif Sollid called it one of the most promising shale opportunities in North America. ConocoPhillips sees potential for the Montney to deliver significant production and cash flow to the company, executive vice president of production drilling and projects Al Hirshberg said in November.

Shell will invest more money this year in the Duvernay than any other shale field except the Permian Basin in West Texas, the most productive U.S. shale play, spokesman Cameron Yost said.

“We may learn something in the Permian that becomes applicable in the Montney, and vice versa,” Yost said.

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The Duvernay in central Alberta is a shale play, while the Montney, straddling northern Alberta and British Columbia, is technically a formation of siltstone, a more porous rock. Drilling and extraction techniques are the same, however, and many in the industry use the term shale for both.

The Duvernay is comparable to the Eagle Ford shale field in South Texas. The Montney is unique, with its enormous gas resources and extremely thick rock formation containing several different levels at which oil and gas can be drilled, said Mike Johnson, technical leader of hydrocarbon resources for the National Energy Board.

Weak prices in an oversupplied natural gas market have hampered development, along with added costs of shipping from the far-flung fields and limited capacity on pipelines. That makes it harder to compete with producers in shale gas plays such as the Marcellus in the northeastern United States.
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Russia's Gazprom Neft sees Bazhenov shale oil commercial output in 2025

March 1 , 2018
KHANTY-MANSIISK, Russia, (Reuters)

Russia’s Gazprom Neft expects to start commercial production from Bazhenov formation, the world’s largest shale oil resource, in 2025 provided it can reduce lifting costs from current estimates for the project, company officials said.

The International Energy Agency describes Bazhenov as the world’s largest source rock, a bed of ancient organic matter dating back to the Jurassic period which has given rise to most of the crude oil pumped from the fields of West Siberia.

Production of such oil is more costly than the extraction of the oil from conventional reservoirs.

“We understand that this is a very serious technological challenge,” Alexei Vashkevich, head of geological exploration and resource base development at Gazprom Neft, told reporters.


For the project to be viable, lifting costs needed to fall to 8,500 roubles ($151) per tonne, Vashkevich said, without disclosing current estimates.

Kirill Strizhnev, who oversees the Bazhenov project for Gazprom Neft, said commercial production might start in 2025.

Gazprom Neft, which estimates that it can potentially extract 400 million tonnes of oil equivalent (8 million barrels per day) from Bazhenov, currently produces 150 tonnes per day from the formation.

The company initially planned to tap Bazhenov jointly with Shell but the international major withdrew from the project in 2014 following international sanctions against Russia for its role in Ukrainian crisis.

$1 = 56.26 roubles Reporting by Oksana Kobzeva Writing by Vladimir Soldatkin Editing by Edmund Blair

Le schiste ne s'exporte pas

Par Ludovic Dupin - Usine Nouvelle le 29 octobre 2015

Les gaz et pétrole de schiste n’ont pas encore quitté l’Amérique du Nord ! « Les États-Unis comptent 100 000 puits actifs, le Canada 20 000. Dans le reste du monde, il en existe entre 500 et 1 000 » précise Jean-Louis Schilansky, le président du centre hydrocarbures non conventionnels (CHNC) qui vient de présenter un panaroma de l’exploration et de l’exploitation. « La question est de savoir si ce phénomène restera purement nord-américain. Franchement, je ne le crois pas », affirme-t-il. Aujourd’hui, l’essentiel de la production mondiale d’hydrocarbures de schiste provient des États-Unis (4,2 millions de barils par jour et 350 Gm3 de gaz de schiste), du Canada (1 million de barils par jour et 30 Gm3 de gaz) et d’Argentine (50 000 barils par jour et 1,5 Gm3 de gaz).

Indépendance et décarbonisation

Toutefois, le CHNC dénombre dix autres pays qui ont engagé des recherches sur le sujet : Allemagne, Afrique du Sud, Algérie, Arabie saoudite, Australie, Chine, Danemark, Pologne, Royaume-Uni et Russie. Dans la majorité de ces pays, on retrouve des raisons communes à cet intérêt pour les hydrocarbures non conventionnels. D’une part, une volonté d’accroître leur indépendance énergétique. La Pologne veut s’affranchir de la Russie et le Royaume-Uni veut compenser la baisse de sa production d’hydrocarbures en mer du Nord. D’autre part, ils partagent un souci de décarbonisation de l’économie. L’Allemagne, la Chine et le Danemark remplacent des centrales au charbon par des centrales à gaz. Les recherches exploratoires sont plus ou moins couronnées de succès. Les études sur la Pologne annonçaient 4 000 Gm3 de gaz de schiste dans le sous-sol.

Après les premières prospections, ce potentiel a été réduit à 550 Gm3. De même, au Danemark, les recherches de Total n’ont pas produit les résultats escomptés. À l’inverse, au Royaume-Uni, les puits forés ont révélé un potentiel très important de 700 Gm3 de gaz de schiste, soit dix ans de consommation nationale. En Allemagne, les études évoquaient 500 Gm3 de réserves. Elles ont finalement été réévaluées à près de 1 300 Gm3 par l’Institut fédéral allemand des géosciences. La révolution des schistes peine à se mondialiser.

Gazprom envisage de produire du pétrole de schiste en 2018

04 Juin 2015 euronews

Gazprom Neft annonce que la production commerciale de pétrole de schiste démarrera en 2018 à partir de son puits d’exploration situé dans le bassin de Bajenov.

La branche pétrolière du géant gazier russe Gazprom précise qu’elle vise une production d’environ 40 000 barils par jour d’hydrocarbure de schiste, alors que le site de Bajenov pourrait contenir jusqu‘à 22 milliards de tonnes de pétrole de schiste selon le ministère russe de l’Energie.

Depuis septembre 2014, les sanctions occidentales contre la Russie visent les transferts de hautes technologies utilisées pour l’exploration ou la production de pétrole non conventionnels.
Gazprom, qui a acquis les techniques de fracturation hydraulique, entend ainsi poursuivre ses projets avec ou sans l’aide des occidentaux.

D’autant que le groupe russe a resserré ses liens avec Pékin.

Ce mardi, Gazprom a annoncé que la Chine avait amorcé la semaine dernière la construction d’un pipeline visant à exporter du gaz russe.

Ces travaux s’inscrivent dans le cadre de l’accord signé en mai 2014 entre la Chine et la Russie sur l’acheminement de 38 milliards de m3 de gaz par an durant 30 ans, via le gazoduc baptisé “Force de Sibérie”.
Ce pipeline devrait être fonctionnel en 2019.

Canada’s New Shale Oil Field Could Rival the Bakken

By PETER KRAUTH, Resource Specialist, Money Morning May 29, 2015

Canada's energy industry may be most famous for its world-class oil sands resources. But a new shale oil field could surpass the oil sands as Canada's largest untapped oil reserve.

In fact, it could even rival the massive Bakken shale of North Dakota in terms of recoverable oil.

This area lies north of British Columbia and east of the Yukon. It's the Northwest Territories.

Recent data from the National Energy Board (NEB) and the Northwest Territories Geological Survey shows that this area holds as much as 200 billion barrels of shale oil reserves. That compares to U.S. Geological Survey estimates that the Bakken shale formation will yield 4.3 billion barrels.

Not all of this Canadian oil is necessarily recoverable. But the Canol and Bluefish shales contain a total approaching 7 billion barrels of economically viable resources.

Here's a look at the vast potential of Canada's Northwest Territories…

A New Shale Oil Field with "Significant Potential"

Shale Oil FieldMajor oil companies have been exploring this area just 145 kilometers south of the Arctic Circle, known as the Mackenzie Plain, for some time.



Major oil companies have been exploring this area just 145 kilometers south of the Arctic Circle, known as the Mackenzie Plain, for some time.

Oil producers such as Husky Energy Inc. , Imperial Oil Ltd., Royal Dutch Shell Plc., and ConocoPhillips have performed exploratory drilling in the Canol field.
A total of 14 exploration licenses have been granted with $628 million in work commitments dating back to 2010.

The Canol Field could hold as much as 145 billion barrels of oil. That's comparable to Texas' Permian basin, where about 3% of oil in place is currently being recovered by operators.

The Bluefish shale has yet to even be explored. It could hold up to 46 billion barrels.

David Ramsay, Minister of Industry, Tourism and Investment for the Government of the Northwest Territories, commented on the NEB data, saying, "This study confirms what we have known all along – that there is significant petroleum potential in the Sahtu."

Developing these fields could be a ways off, however. Some living in the territory as well as Greenpeace oppose fracking, claiming it could contaminate groundwater.

Perhaps an even larger obstacle to development is infrastructure. The area's remote location currently lacks such basic services as an all-weather road. A pipeline system to carry the recovered oil and gas to market will also need to be built eventually.

So now the big question: Can investors profit from this new Canadian shale oil field?

The central Northwest Territories is home to around 200 billion barrels of oil, according to a new assessment released on Friday.

Canada’s National Energy Board (NEB), working with the NWT’s Geological Survey, says the Canol Shale holds an estimated 145 billion barrels of oil, with the Bluefish Shale accounting for a further 46 billion barrels.

According to the NEB, this is scientists’ first real insight into the size of these reserves, located west of Great Bear Lake.

“The numbers are staggering,” David Ramsay, the territorial minister of industry, tourism and investment, told Moose FM.

“We’ve known there’s oil there but when you put numbers to it, those numbers are quite large and quite exciting for the Northwest Territories.

“This is a resource that we get to manage now, in looking at jobs and opportunities for the people of the Northwest Territories.”

Full announcement: NEB and NTGS assess Bluefish and Canol Shales

However, Ramsay noted that extracting any of the oil will require the use of hydraulic fracturing, or fracking.

Fracking remains a contentious issue in the NWT. The territorial government is proposing a new regulatory framework to govern the practice, but the Dene Nation, among others, has called for a slower approach so people can “learn about the process and the risks involved” before decisions are made.

“If there’s no hydraulic fracturing, those resources can’t be extracted,” admitted Ramsay.
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China's CNPC Makes 1st Tight Oil Find over 100M Tons

BEIJING, May 26 (Reuters)

Chinese state-owned energy giant China National Petroleum Corp (CNPC) has discovered more than 100 million tonnes of tight oil geological reserves in its Changqing field, a company-run newspaper said on Tuesday.

The discovery, located in the western province of Shaanxi, is the first Chinese tight oil find to surpass 100 million tonnes, the China Petroleum Daily said.

Technically recoverable reserves may be considerably lower. Tight oil production capacity in the Ordos basin, where Changqing is located, is more than 1 million tonnes, the paper said.

CNPC is Asia's largest oil producer and the parent of PetroChina Co Ltd. .

In the first quarter of 2015, Changqing produced 6 million tonnes of crude oil, or 487,600 barrels per day, according to the official Xinhua News Agency's China Oil, Gas & Petrochemicals (OGP) newsletter.

Gazprom Neft drills first tight oil Achinsk field well in Russia

8th May 2015

The first exploratory well has been drilled at the Achinsk field (Tomsk Oblast, under development by Gazprom Neft subsidiary Gazpromneft-Vostok), part of a federal project to establish a regional testing ground to identify effective technologies for the development of hard-to-recover (tight) reserves.

Operations, financed by Gazprom Neft, are also aimed at conducting a study of the unconventional hydrocarbon reserves of the Bazhenov formation.

Sampled at a depth of around 2,600 metres, approximately 30 metres of core samples have been extracted from the Bazhenov formation and subsequently transferred to the All-Russian Research Geological Oil Institute (VNIGNI, the primary institute of the Federal Subsoil Resources Management Agency).

Analysis of the material obtained will allow further clarification of the structure of the Bazhenov formation, as well as delivering insights into the long-term prospects for production from these deposits, and the identification of optimum strategies for their development. Drill samples will also be studied by specialists from the Gazprom Neft Scientific and Research Centre.

The Bazhenov formation is a key source of unconventional hydrocarbon reserves. A specific geological stratum identified in the centre of Western Siberia, this rock formation runs to depths of 2,000–3,000 metres. While the stratum covers an area of approximately one million square kilometres, it is comparatively thin, with a thickness of only 10–40 metres. Optimistic estimates suggest that oil reserves of the Bazhenov formation could amount to as much as 100–170 billion tonnes. The development of these reserves in Russia is currently awaiting the selection of appropriate technologies for full-scale commercial production.

An agreement on the establishment of a testing ground for the development of technologies for the exploration and production of hard-to-recover reserves was signed in March 2014 between the Ministry of Natural Resources and Environment of the Russian Federation and the Administration of the Tomsk Oblast. The project is being implemented by the Tomsk association, the Research and Development Centre for Innovation in Subsoil Use, of which Gazprom Neft is a member.

Gazprom Neft is also actively involved in the investigation of the Bazhenov formation in other regions. The company is working on the selection of technologies for the development of these strata in the Yuzhno-Priobskoye and Krasnoleninsk fields (Khanty-Mansii Autonomous Okrug). The Gazprom Neft Scientific and Research Centre also partners another federal programme in this area, again directed at the further evaluation of the key characteristics of the Bazhenov formation and the identification of potential technologies for its development. This project is being implemented by the Engineering Centre of the Moscow Institute of Physics and Technology, this institution having won a competition held by the Ministry of Education and Science of the Russian Federation for the selection of academic developments of state significance under its “Priority Research Initiatives for the Development of the Russian Science and Technology Sector, 2014–2020” programme.

Non-U.S. Shales Prove Difficult to Crack
Exxon, Shell and others are pulling back from once-promising shale finds in Europe, Asia

By
Justin Scheckand
Selina Williams
March 18, 2015 11:20 p.m. ET

After spending more than five years and billions of dollars trying to re-create the U.S. shale boom overseas, some of the world’s biggest oil companies are starting to give up amid a world-wide collapse in crude prices.

Chevron Corp., Exxon Mobil Corp. and Royal Dutch Shell PLC have packed up nearly all of their hydraulic fracturing wildcatting in Europe, Russia and China. The reasons vary from sanctions in Russia, a ban in France, a moratorium in Germany and poor results in Poland to crude prices below what it can cost to produce a barrel of shale oil.

Chevron halted its last European fracking operations in February when it pulled out of Romania. Shell said it is cutting world-wide shale spending by 30% in places including Turkey, Ukraine and Argentina. Exxon has pulled out of Poland and Hungary, and its German fracking operations are on hold.

The result: Outside the U.S., where fracking has produced a historic glut of oil, only China, Argentina and Canada have commercial shale production, the U.S. Energy Information Administration says,though America holds less than 10% of the world’s estimated shale reserves. Europe, including Russia, and China alone have nearly triple the reserves of the U.S., according to the EIA.

“The pace of development outside North America is slower everywhere than people thought it would be,” Simon Henry, Shell’s chief financial officer, said in a recent interview.

A recovery in oil prices could change the equation, giving big companies more room to take risky bets on shale. And bright spots for shale prospectors outside North America still exist.

(..)

“The publicity is bad, but the reality is it’s going to be down to the smaller companies to prove the play, as they did in the U.S.,” says Oisín Fanning, the executive chairman of San Leon Energy PLC, a U.K.-listed explorer that announced a commercial gas discovery in Poland in February and expects its first sales in early 2016.

Fracking works by using water, sand and chemicals to fracture underground rock and hold the cracks open, allowing oil and gas trapped in the rocks to flow. Unlike the long-term projects that the world’s biggest oil companies specialize in, shale wells tend to have short lives, and developing a shale field requires drilling many holes over a short period.

The technology worked well for small producers in North America, but oil giants like Exxon and Shell, with their thick layers of management and slow drilling-approval processes, largely missed out on the profits there.

(..)

One problem the companies have faced is the high cost of shale drilling outside the U.S. when oil prices are low. Exploration wells in new areas require experimentation and lack the economies of scale in a more developed area. Wells in Poland and China can cost up to $25 million each, while American wells on average cost about $5 million, said Melissa Stark, lead author of a 2014 shale report by Accenture LLP.

(..)

Ms. Stark of Accenture said countries with strong national oil companies such as China, Argentina and Saudi Arabia were more likely to lead shale development outside the U.S. They have a mandate to extract their countries’ resources, government support, and lots of money.

“You need a player with deep pockets and who can be there for several years,” she said. State-run companies “are there for the long term so they can invest for the long-term.”

Japan enters a new stage of shale oil drilling

At 10:50 am on May 23, a drilling pipe was gradually and quietly spinning downward and reaching a depth of around 25 meters when I got on the platform of a 50-meter high drilling rig in search of shale oil.

The scene like this may not be too unusual in Texas but this was happening in Akita, about 600 km
north of Tokyo. That’s where Japan Petroleum Exploration started its horizontal drilling project just 80 minutes prior to my arrival on the platform.

Speaking to the media on a tour of its onshore Fukumezawa oil field on the border of Oga Peninsula in western Akita, Japex officials called the project both a demonstration of the technology and a chance to commercialize output from the Onnagawa tight formation.

“The purpose of this well is to verify horizontal well and multi-stage fracturing technologies,” Satoru Yokoi, geologist of Japex’s Japan-Onnagawa shale oil project team, said during a press briefing at the drilling site. “Of course, we are also looking into commercialization of our works here.”

Japex hopes its first horizontal shale oil drilling will lead to more unconventional oil output and replace that depleting conventional production. So far, Japex is the only Japanese upstream company that has undertaken shale oil drilling activities in the country. Prospects and potential for shale oil production in Japan are yet to be known, and there are no publicly available data.

Japan had 50.13 million barrels of recoverable reserves of crude in fiscal 2012-13 (April-March), according to the Japan Natural Gas Association data. In the same fiscal year, Japan produced 13,079 b/d of domestic crude, representing just 0.4% of its total imports of 3.63 million b/d, according to Ministry of Economy, Trade and Industry data.

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“As part of the demonstrative test, we are hoping to produce around 100 kl/d [629 b/d of crude] from the horizontal well and multi-fracturing,” Kiichiro Kodama, general manager of administration at Japex’s Akita district office, told Platts on the sidelines of the drilling site. Kodama said that the Fukumezawa oil field currently produces around 15 kl/d (94 b/d) of conventional crude.
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Total confirme sa stratégie en Russie en s'associant avec Loukoïl dans le pétrole de schiste

Les Echos 23/05/2014

Malgré les tensions entre Moscou et Kiev, Total crée une co-entreprise avec le russe Loukoïl pour l'exploitation du pétrole de schiste en Sibérie. Il s'agit d'une des plus vastes réserves au monde.

Malgré les tensions en Ukraine, Total continue résolument d'investir en Russie . Vendredi, le groupe pétrolier français a annoncé avoir scellé sa co-entreprise avec le russe Loukoïl pour explorer et exploiter les réserves de pétrole de schiste en Sibérie occidentale. Les négociations, déjà évoquées au mois de mars par le "Financial Times", se seraient cependant tenues avant l'annexion de la Crimée par la Russie et les sanctions qui s'en sont suivies envers Moscou.

La joint-venture sera détenue à 49% par Total et 51% par Loukoïl. Le russe sera chargé d'évaluer "la faisabilité technique d'un développement des ressources potentielles en pétrole de schiste" du gisement de Bazhenov, a indiqué Total dans un communiqué. La première campagne de forages d'exploitation est prévue pour 2015. "Notre expertise internationale, conjuguée à l'expérience de Loukoïl dans la région, contribuera à un partenariat équilibré", a souligné Christophe de Margerie.

Une exploitation dès 2015

Pour le groupe pétrolier français, il s'agit de "conforter sa position dans les hydrocarbures non conventionnels , un domaine où le groupe a développé une expérience significative à travers ses différents projets", explique le PDG de Total. Le gisement de Bazhenov, que la co-entreprise pourra exploiter sur une superficie de 2.700 km2 dès 2015, fait partie des formations de pétrole de schiste les plus vastes et les plus prometteuses au monde.

Présent depuis plus de 20 ans en Russie, Total entend y poursuivre ses affaires, malgré le climat économique dégradé. Le pétrolier français, qui détient 17 % du capital de Novatek - le plus grand producteur de Russie -, s'est également associé à celui-ci dans le projet de gaz naturel liquéfié de Yamal, au côté du chinois CNPC. Un projet gigantesque à 27 milliards de dollars dont la production de GNL, qui doit démarrer en 2017, pourrait atteindre jusqu'à 15 millions de tonnes par an à moyen terme. Lors de la dernière assemblée générale de Total, Christophe de Margerie avait estimé que la crise ukrainienne n'affecterait que très faiblement ce projet crucial pour le groupe, malgré d'éventuels "problèmes de financement".

Préserver les intérêts des entreprises françaises en Russie

Le pétrolier français a toutefois mené campagne auprès du gouvernement français afin que celui-ci tienne un discours rassurant sur les relations économiques entre la France et la Russie, appelant à "prendre en compte l'intérêt des entreprises françaises", rapporte le "Wall Street Journal". Durant une visite au Mexique à la mi-avril, Christophe de Margerie a ainsi fait part de ses inquiétudes à François Hollande.

"La Russie est un pays stratégique pour Total", soulignait récemment Yves-Louis Darricarrère, le responsable de l'exploration et de la production pour le groupe. Total estime ainsi que la Russie deviendra le premier fournisseur de pétrole et de gaz d'ici 2020, tablant sur une production d'hydrocarbures de 400,000 barils d'équivalent pétrole par jour, soit le double du niveau actuel. Des réserves cruciales pour répondre à la demande grandissante des consommateurs asiatiques, toujours plus consommateurs d'énergie, et également, si besoin, pour approvisionner ses raffineries en Europe. Comme par le passé, Total fait fi des tensions politiques, privilégiant ses actifs stratégiques. Comme le répète Christophe de Margerie, il faut "aller là où se trouve le pétrole".

Pétrole de schiste : une révolution ?

Par Les Echos | 05/05 Sylvain Berthelet analyste gérant chez SMA Gestion.

Une baisse des cours mondiaux du pétrole pourrait tuer dans l'oeuf l'essor des hydrocarbures non conventionnels et remettre l'Opep au centre du jeu.

Le 28 avril, Continental Resources, un producteur d'hydrocarbures non conventionnels dans la formation de Bakken (Dakota du Nord), annonçait triomphalement la production du milliardième baril de pétrole brut de son emblématique champ, « la plus importante découverte au monde depuis plus de quarante ans ». Cette annonce fait écho aux prévisions établissant l'indépendance énergétique prochaine des Etats-Unis vis-à-vis de l'Opep. La balance énergétique américaine s'est certes améliorée grâce à une production de brut en hausse d'environ 30 % en deux ans, mais il serait imprudent d'extrapoler. Les infrastructures d'exploitation et de transport sont coûteuses, et le taux de déclin des puits est très important. Tout cela débouche sur un coût du capital élevé pour des résultats souvent peu pérennes. Et tout est question d'interprétation. La découverte de pétrole dans le Bakken remonte à 1951 ! Mais l'exploitation n'était pas viable économiquement à l'époque. Il est donc plus prudent d'affirmer que c'est la hausse des cours qui a rendu l'exploitation non conventionnelle possible que de déclarer que cette activité serait une solution au problème de l'énergie chère.

Une baisse des cours mondiaux pourrait tuer dans l'oeuf cette « révolution » et remettre l'Opep au centre du jeu. Le retour à la pleine capacité de production et d'exportation de certains acteurs (Libye, Irak, Iran…) ou un ralentissement de la demande émergente pourraient ainsi conduire à quelques années de cours bas, ce qui fragiliserait nombre d'investissements récents outre-Atlantique et ailleurs. En fait, des solutions plus durables se mettent en place dans l'ombre. C'est par la variété de l'offre énergétique et, surtout, par une croissance moins énergivore que les Etats-Unis - et les autres grandes économies - continueront d'alléger le fardeau du coût de l'énergie.

The EIA’s Drilling Productivity Report, Is Productivity Really Improving?
by Ron Patterson Posted on April 14, 2014

Unfortunately that data is a little hard to find. The very latest data is almost one year old. From May 29, 2013:

US shale oil is increasing the marginal cost of production

Sanford C. Bernstein, the Wall Street research company, calls the rapid increase in production costs “the dark side of the golden age of shale”. In a recent analysis, it estimates that non-Opec marginal cost of production rose last year to $104.5 a barrel, up more than 13 per cent from $92.3 a barrel in 2011.

Marginal cost rose more than 13 percent in 2012 but what did it do in 2013 and what is it in 2014? And how can drilling companies make money at that cost per barrel? Well the answer is, they can’t.

Even with crude prices above $100 a barrel, U.S. independent producers will spend $1.50 drilling this year for every dollar they get back from selling oil and gas and will carry debt that is twice as much as annual earnings, said Ryan Oatman, an energy analyst with SunTrust Robinson Humphrey Inc., an investment bank in Houston.

By contrast, the net debt of Exxon Mobil Corp., the world’s largest energy explorer by market value, is less than half of the cash earned from operations last year. The company will spend 68 cents for every dollar it gets back this year, according to company records and analyst forecasts compiled by Bloomberg.

So far, oil prices have been high enough to keep investors interested in the potential profits to be made in shale, Oatman said.

“There is a point at which investors become worried about debt levels and how that spending is going to be financed,” Oatman said. “How do you accelerate and drill without making investors worried about the balance sheet? That’s the key tension in this industry.”