№7 July - August 2010Table of contents Issue Archive
№ 6 (June 2010)
The rapid growth in U.S. shale gas production is perplexing global gas producers. Gazprom has already postponed the launch of the Shtokman gas condensate field development in the Barents Sea with its 3.9 trillion cubic meters of gas – the Russian monopoly’s first LNG project (excluding Sakhalin-2, where the company did not have to build the infrastructure).
By Svetlana Kristalinskaya
This is the second in a three-part series on shale gas in Russia and Eurasia. Part 1 can be read here: "Shale Gas: Global Revolution or Yet Another Bubble?"
The spike in U.S. shale gas production and falling demand for natural gas in the wake of the global financial crisis triggered lower U.S. spot market gas prices. This, in turn, prompted the project’s participants – Gazprom, Total and Statoil – to question the need to launch the Shtokman field quickly. Part of its production was meant to feed the Gazprom-run national gas supply system, while the rest was intended for LNG deliveries to the U.S. and European markets.
As a result, the start of gas production at Shtokman was postponed and the issue of producing LNG came into question. According to Shtokman Development AG chief Yury Komarov, if LNG production is included, investment yields will not meet shareholder requirements. He explained that LNG is currently at least twice as cheap as contracted pipeline gas to Europe.
“The Atlantic LNG market is not attractive at the moment and will not be so for the next few years. Our task is to get the Shtokman project up and running as soon as possible, and be prepared to launch LNG production,” Total Russia Vice President Herve Madeo said.
Meanwhile, Statoil CEO Helge Lund noted at a recent video conference that “in the short term, the U.S. shale gas market has undoubtedly impacted the Shtokman project.” Yet, he was sure that “in the long-term, Shtokman will enter this market.”
Why Would Soviets Develop Shale Gas?
“Four years ago, it was accepted wisdom that the United States, long past being self-reliant in crude oil and transportation fuels, was irrevocably dependent on growing LNG imports to meet domestic gas demands. Higher prices and technological advances have joined to refute this belief, to the point where North American shale gas is viewed in some quarters as the magic bullet to solve all U.S. energy security concerns. This belief, and the policy agendas it has fostered, is reminiscent of – but far from identical to – Western Europe’s attitudes toward North Sea gas some 20 years ago, or even the so-called North American ‘gas bubble’ of some 30 years ago,” Gazprom Export head Alexander Medvedev said in a presentation that was prepared for CERAWeek in Houston in March.
Though talking of the possible negative environmental consequences of shale gas production, Medvedev argued at the same time that Gazprom is not against shale gas. “In fact, we believe that the abundance of economic shale gas will be good for the gas industry in alleviating concerns about security of supply. If the environmental questions can be addressed, Gazprom itself will consider taking positions in U.S. shale resources. Let’s develop this industry, but prudently. Shale gas holds great promise for resource development and for much needed tax revenues for state governments,” his report read.
A source at Gazprom explained to OGE that the Russian giant is mulling the acquisition of a U.S. shale gas producer in order to study the production technology and then use it in other areas. Gazprom Promgaz chief research officer Vladimir Khryukin notes that Russian experts plan soon to set up a meeting with U.S. colleagues on assessing shale gas prospects.
Medvedev’s statement contradicts comments made by Russian officials and top Gazprom managers on the record, but it confirms the need for Russia to have an official position on the “shale revolution” and to assess the feasibility of shale gas production at home, as suggested at a roundtable discussion in the State Duma in late March.
Opinions varied during the roundtable. Khryukin told OGE that neither the Soviet Union nor Russia had ever conducted studies on shale gas production. He said, “The Soviet Union simply processed shale oil (30 percent of which is composed of organic material). Such shale is no good for gas production since its fissures are filled with bitumen. The Americans, however, claim they can produce natural gas from shale with less than 3-5 percent organic content,” says Khryukin.
“Why should we have researched shale gas production, if Russia had such huge reserves of traditional Cenomanian gas?” the source at Gazprom echoed.
According to Khryukin, the structure of shale is close to that of coal-bearing formations, so half of the roundtable presentations focused on producing gas from coal seams. After hesitating for a long time, domestic companies finally took up this technology – and began producing oil by extracting it from bazhenites, which are essentially the “twin brothers” of shale gas.
“The Quiet Revolution”
The Americans are making yet another “bubble”, just as like they did with coal-bed methane production in the second half of the 1990s, asserts Lev Puchkov (see OPINION), the president of the Moscow State Mining University, Ph.D., Professor, and member of the Russian Academy of Sciences (RAN).
Yet Russia’s LUKOIL was the first to announce that shale gas had changed the world. And the company has reason to be nervous. Its U.S. partner ConocoPhillips plans to offset its debt burden by selling half of its 20 percent stake in LUKOIL while at virtually the same time, announcing it had decided to accelerate the development of its Eagle Ford shale project in the United States and to enter the shale gas production market in China.
Speaking in a different venue but at almost the same time as the head of ConocoPhillips CEO Jim Mulva, LUKOIL Vice President Leonid Fedun said the global oil and gas industry had witnessed a “quiet revolution” over the past few years. “The oil and gas world has changed fundamentally. This is reflected by price expectations existing in the world,” he said.
Fedun explained that breakthroughs in upstream technology meant companies could view hydrocarbon reserves as “inexhaustible for several generations and also accessible currently.” He said this viewpoint completely changed the assessment of the entire oil industry.
In particular, Fedun highlighted alternative upstream technologies such as shale gas and shale oil production. “We currently see very quiet global distribution of the markets, including in Europe,” he said.
Fedun also noted oil production from the Bazhenov formation (which is essentially shale oil – OGE) in Russia. According to him, production development boils down to favorable marketing conditions, demand and tax benefits. He believes that in order to allow companies to tap into these difficult reserves, Russia needs a fundamental change in its tax system.
Natalia Andreeva, the director of the Institute of Integrated Planning for Field Construction, noted during the above-mentioned roundtable that LUKOIL’s subsidiary RITEK has been engaged in Russia in the test development of oil production from the Bazhenov formation, but noted it is “a costly affair” and needs state support as was the case in the U.S. with shale gas production.
The management standing behind Russia’s other LNG project seems unfazed by shale gas production. Leonid Mikhelson, the head of NOVATEK (which is preparing an LNG plant project on Yamal Peninsula), said shale gas reserves were impressive and added that the company was taking this factor into account in its development strategy. However, Mikhelson noted it is expensive to develop oil shale and said shale reserves are only sufficient to cover 5-10 years of the U.S. market.
“Yet shale gas production costs are high, and this is stimulating NOVATEK to boost its competitive edge,” he said adding that U.S. demand for natural gas could grow between 2016 and 2020.
According to Medvedev, the development of shale gas “is real, but the prices which make the technology profitable сould also give LNG a competitive edge on the U.S. market, perhaps in the long run. This is the baseline of Gazprom’s strategy on the domestic LNG market as well as being an equal competitor to U.S. shale gas and other gas suppliers.”
Vladimir Vysotsky, director of the Petroleum Department at Zarubezhgeologiya Research Institute, believes Shtokman LNG will become profitable in the U.S. market starting at a price of $270 per 1,000 cubic meters. And yet a source in Shtokman Development AG told OGE, “Do not trust anyone. Until we sign the relevant tenders, no one can say anything about price parameters.”
“Shale gas is a challenge. Even if it turns out to be a temporary fashion and there are no long-term dramatic changes on energy markets. The ‘shale revolution’ has de-facto, caused a paradigm shift in how consumers view the world. Now, every time the price of imported fuel jumps, consumers will look down under their own feet and think about the promise of local resources,” says Energy and Finance Institute chief expert Nikolai Ivanov.
According to Ivanov, the economics of shale projects differ from traditional gas production, and this difference hides serious money. In fact, a horizontal well drilled in a shale formation produces gas for a much shorter amount of time than a conventional gas well. Furthermore, shale wells are significantly more expensive. The price difference is compensated by a higher flow rate of shale wells. But in order to maintain production, more and more new wells are required.
According to Vysotskiy, shale well production yields reach 500,000 cubic meters a day at the initial stage, sinking 70 percent over the course of a year and then slowly dropping to 9-15 percent. The life cycle of a well costs $3-10 million over 8-12 years.
Ivanov notes this was the reason for inflated capitalization of companies that installed the first shale wells and received rapid gas production growth. At the time, business analysis was based on traditional ideas about the economics of gas production, not taking into account the need to continually invest in sustainable production. “Now we see estimates from independent analysts showing that the real cost of shale gas production is much higher than the figures initially announced by producers,” he says.
Experts use the example of Chesapeake to question the high profitability of shale gas projects. Texas-based geologist Arthur Berman came to the conclusion that the true production cost of shale is several times higher than the $3.50 per thousand cubic feet stated by Chesapeake.
It is true that after a well is installed it is relatively cheap to manage, and operating expenses are about $100 per 1,000 cubic meters. Still, according to Berman, the hyped horizontal drilling technology brings much less than commonly stated. By the end of 2008, more than 11,800 wells had been drilled at the Barnett shale play, each costing more than $3 million (including the cost of acquiring a license, actual drilling and efficient maintenance over the production life of the well). Yet the estimated ultimate recoverable (EUR) for horizontal wells was a mere 0.81 billion cubic feet (22.9 million cubic meters) – more than three times below the originally planned yield.
In any case, well productivity has been falling since 2003; while the average EUR indicator at Chesapeake Energy began production was about 32.3 million cubic meters per well (including both horizontal and vertical wells), it fell to 16.7 million cubic meters by 2008.
Ivanov notes that according to Barnett production data, the yield of existing wells was falling much faster than at traditional fields. The average lifespan of U.S. gas wells is some 30-40 years, but about 15 percent of wells drilled at Barnett in 2003 were depleted after five years of production. According to Berman’s calculations, the shale gas wells at Barnett have a ceiling of 8-12 years of service and only a few remain profitable after 15 years of operation. Another study – at the Haynesville deposit – revealed an average EUR of 48.7 million cubic meters of gas per well (while operating companies were citing figures of about 180-200 million cubic meters).
Accordingly, some experts estimate the real cost of shale gas production to be some $7.50-8.00 per 1,000 cubic feet per day ($265-282 per 1,000 cubic meters). The volume of investments required to fully develop Barnett is astronomic; at least $75 billion (in 2008 prices) is required merely to drill and maintain the wells without calculating the infrastructure.
Interestingly, Berman, who has published over 40 articles on the subject in World Oil, was forced to stop writing on shale gas after complaints were received from two companies engaged in shale gas production. This surfaced in a blog by Perry Fischer, World Oil’s former editor-in-chief, who was sacked after refusing to remove Berman’s article from the issue.
(to be continued in the July issue)
Lev Puchkov: Shale gas – the next bubble
U.S. natural gas companies, particularly the now defunct Enron, played off a random discovery at an average field with no physical or chemical links to methane resources and which was geologically situated in the coal formations of the San Juan coal basin.
Meanwhile, we said that the deposit was not coal-bed methane, which has very strong physical and chemical links to solid coal, but free-methane formation in layers of coal - in cavities, cracks and so on. Further research confirmed our opinion.
But the total production volume turned out to be quite good – 30 billion cubic meters of methane. Regrettably, U.S. natural gas companies appropriated the rare geological phenomenon of San Juan as their own technology achievement and claimed this methane was actually extracted from coal itself.
So eventually the coal-bed methane bubble burst as predicted. The real picture showed that thousands of wells drilled for coal-bed methane production were empty. That was a huge failure for the U.S. natural gas industry and natural gas imports increased. Other sources of methane gas, offshore production and Alaska-based production could not make up for planned output levels.
The question is: where are the trillions of cubic meters of coal-bed methane, which marketing departments were selling to the world 15 years ago in the same fashion they are selling trillions of cubic meters of shale gas today? The coal is found at a depth of 700 meters and it is accessible there. But this coal will not provide methane and it is impossible to extract the gas from the physical-chemical bonds between the materials.
We and the Americans studied the data in the geological service, and, in general, they acknowledged their defeat in coal-bed methane production. And now here comes bubble #2 – shale methane.
Yes, shale deposits, like many other deposits, sometimes have geologic fault lines, fissures and cracks, which form reservoirs that fill with free methane. But these reservoirs are rare and rather an exception to the rule, that is, a geologic phenomenon. Natural gas constitutes only a fraction of a percent in the total mass of shale rock. There isn’t a single cost-effective technology for shale gas production. We studied the retention capacity of shale gas in Donbas coal mines; we know how much gas is there and how difficult it is to get out. This data was published in Soviet literature in 1960–1970s and is open to analysis. With all due respect to the power of American technology, which in this case is manifest in drilling technology, it must be noted that no upstream technology can produce something which is not there. In this case, commercial reserves of natural gas.