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First LNG-Fueled Hydraulic Fracturing Completed in Eagle Ford Play

by  Karen Boman
Rigzone Staff

The liquefied natural gas (LNG) division of Calgary-based Ferus LP successfully completed in October what the company believes to be the first-ever hydraulic fracturing operation utilizing liquefied natural gas (LNG) as engine fuel in North America.

Ferus’ LNG Division was engaged by a major oil and gas service company in the United States to conduct the pilot project, which involved six dual-fuel 2,250 horsepower pressure pumper units, powered by LNG, to stimulate well performance in the south Texas Eagle Ford shale.

The dual fuel systems allow for natural gas and diesel to be consumed simultaneously with no decrease in performance, Jed Tallman, manager of market development for Ferus LNG, told Rigzone. Approximately 10,000 gallons of LNG was used in the pilot project, which took place in the southwestern portion of the Eagle Ford play.

While the company cannot discuss the plans of the operator involved in the pilot project, Ferus LNG has been contacted by numerous operators and service companies regarding LNG as a low-cost, environmentally superior alternative fuel, Tallman said.
The increase in interest by operators and service companies in using LNG for hydraulic fracturing has been dramatic.

“Because of the large amounts of diesel consumed in fracturing fleets, the use of LNG as an alternative fuel will result in cost savings for the operator or service company, not to mention a significant reduction in greenhouse gas emissions,” Tallman commented.

“LNG offers significant environmental and cost-saving advantages and is quickly becoming the alternative fuel of choice for heavy-duty high horsepower on-road and off-road applications in North America,” said Ferus President and CEO Dick Brown in a Nov. 28 statement. “We were very pleased to play such a critical role in this ground-breaking project, and we intend to be at the forefront of this growing industry as more and more diesel consumers make the switch to North America’s abundant supply of natural gas.”

It is difficult to estimate the specific size of the market for LNG in hydraulic fracturing and in other areas such as railroad transportation and trucking moving forward, Tallman commented.

“But given the economic benefits, improved emissions profile, and increased gas production, we feel that LNG will make up a considerably larger percentage of our domestic energy consumption in the future.”

While the use of LNG for hydraulic fracturing is not being specifically done to alleviate criticism of hydraulic fracturing, the improved emissions profile of natural gas certainly is a benefit, Tallman said.

To complete this project, which marks a significant milestone in the adoption of natural gas as an alternative engine fuel, Ferus managed the entire supply chain on behalf of its client including LNG supply, transportation, and on-site storage and vaporization using specialized equipment and highly-trained personnel.

In addition to being a cleaner-burning and less expensive fuel alternative, LNG is non-toxic, non-combustible, non-flammable as a liquid, and dissipates into the atmosphere in the event of a leak or a spill, making it safer than diesel and gasoline, the company said in a statement.

The use of LNG requires specialized fuel handling equipment and additional training for individuals involved in the LNG supply chain.

“As a leading provider of cryogenic liquids for the energy sector, Ferus is uniquely qualified for the undertaking,” Tallman said.

The increased use of natural gas to fuel not only hydraulic fracturing but transportation has grown thanks to the abundance of shale gas in the United States.

The use of natural gas over diesel is becoming more widespread, likely due to the cost benefits associated with fuel switching, according to a Nov. 28 analyst report from GHS Research. GHS referenced Baker Hughes‘ Nov. 26 announcement that it would convert a fleet of its Rhino hydraulic fracturing units to bifuel pumps as a way to improve operational efficiency, lower costs and reduce health, safety and environment impacts. Bifuel is a mix of gas and diesel.

The new pumps use a mixture of gas and diesel, reducing diesel use by up to 65 percent with no loss of hydraulic horsepower. The converted fleet, which meets all U.S. Environmental Protection Agency emissions standards, can also reduce a number of emissions including nitrogen oxides, carbon dioxide and particulate matter.

Baker Hughes first converted a small fleet of its units in Canada; the success Baker Hughes saw with this endeavor prompted to company to convert an entire fleet in the United States. The company is converting several more fleets of Rhino trucks to Rhino Bifuel equipment. Baker Hughes also has a test program in Oklahoma, where a number of light-duty vehicles have been converted to natural gas.

Westport Innovations, which manufactures natural gas-powered truck engines, recently reported it is building a railroad locomotive engine that can run on LNG. During 2012, the company saw “broad consensus” for the first time that natural gas will take material market share in every global transportation market within the next five years, said David Demers, chief executive officer for Westport, during the company’s third quarter 2012 earnings update Nov. 8.

Demers noted that consensus suggests that the company will see 7 percent to 15 percent of the North American trucking industry run on natural gas in 2017.

Westport Innovations will also introduce new natural gas-powered versions of the Ford F-450 and F-550 Super Duty trucks in mid-2013, the company said in a Dec. 3 statement.

“Although current demand for natural gas used in vehicles is minor relative to the demand associated with power generation, industry and residential heating, it is catching on and may soon reach a tipping a point where growth rapidly accelerates, with or without government intervention,” GHS reported.

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Eagle Ford a contender for top U.S. play

By Vicki Vaughan

Highly productive wells and the vast size of the Eagle Ford Shale are combining to make the South Texas shale play a contender for being the nation’s best, according to a new report.

The report, from information and analytics firm IHS, looked at well performance for oil and oil-rich liquids in the Eagle Ford as well as in the Bakken Shale of North Dakota and Montana, currently the nation’s top play. The Bakken has more wells than the Eagle Ford, but so far, on a per-well basis, the Eagle Ford seems to be producing more than the Bakken.

The Bakken is more established, and the Eagle Ford is still developing.South Texas

This IHS report is part of a broader study that’s under way of 27 of the nation’s shale plays.

The IHS analysis shows that “Eagle Ford drilling results appear to be superior to those of the Bakken,” said Andrew Byrne, director of equity research at IHS and the study’s author.

The Bakken shale is the play against which others are measured, Byrne said, because “it was the key play that really opened up development of unconventional resources” using high-tech drilling methods and hydraulic fracturing.

The Bakken first began to show great promise about 12 years ago, Byrne said.

“The results from the Bakken were so strong that it set the standard by which all others will be measured. It was the one play that incited the industry into pursuing these opportunities,” he said.

Now, though, comes the Eagle Ford.

Wells in the Eagle Ford Shale have a stronger flow – 300 to 600 barrels a day or oil and oil-rich liquids, based on average production in a peak month – than in the Bakken, where flow ranges from 150 to 300 barrels a day.

“One of the reasons we really like the Eagle Ford is its potential as a large total resource. It could be one of the best, if not the best, in North America,” Byrne said.

“The Eagle Ford covers such a vast area. That also makes this such a strong play.”

The Eagle Ford sweeps 400 miles from East Texas to counties south of San Antonio and on to the border.

The play “gets uniformly strong results, and that’s making the play look that much bigger and better,” Byrne said.

“All plays essentially have sweet spots. What makes the Eagle Ford so good is that the noncore stuff is delivering strong results also. In some other plays, it’s only the sweet spot that’s economic.”

2012 prediction

The Center for Community and Business Research at the University of Texas at San Antonio has also prepared studies of the Eagle Ford Shale. Center Director Thomas Tunstall predicts that the Eagle Ford Shale will produce 65 million barrels of oil for 2012. Oil production in the Eagle Ford reached 36.6 million barrels in 2011, according to Texas Railroad Commission data.

It’s somewhat difficult to predict production from the shale because the rate of production is accelerating, Tunstall said.

IHS doesn’t yet have an estimate of all the oil that is in the Eagle Ford.

“We’re working on that,” Byrne said.

Last week, Steve Trammel, senior manager of industry affairs for HIS, said in an interview that rig counts are declining in shale plays with much more natural gas than oil because of low natural gas prices.

But drilling is on the rise in shale with oil and “liquids-rich” areas, where wells can tap a mix of oil and condensate, a light oil, and “wet,” or liquid, natural gas, Trammel said.

Looking ahead

In fact, the highest average monthly production in the Eagle Ford is coming from the formation’s liquids-rich window, Byrne said.

Asked which might be the next hot play, Byrne said: “We haven’t officially put out that opinion yet. That will have to be reserved until we finish our study.”

The energy industry is “very creative,” he noted. “It seems like every quarter another play shows up.”

vvaughan@express-news.net

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USA: Apache Finds Huge Shale Gas Reserves in Liard Basin

Apache Corp. has found a huge amount (up to 48 trillion cubic feet) of natural gas in its Liard Basin properties in northeastern BC. All of the gas is targeted to ship to a proposed LNG plant which should be built at Kitimat, according to Refinery News.

As the company says, it is the best unconventional gas discovery in North America. They have rights to drill 430,000 acres within the region.

Because of the low gas price, it is expected that the drilling plans in the Liard region could be very slow.

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Cheap natural gas feeds chemical industry boom

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By Zain Shauk
Published 08:02 p.m., Thursday, April 19, 2012

LAKE JACKSON – The shale boom’s bounty of cheap natural gas is fueling an industrial renaissance on the Texas coast, one that was in full focus Thursday as Dow Chemical announced the latest piece of a $4 billion expansion of its chemical operations in Southeast Texas.

The $1.7 billion plant Dow announced Thursday, one of four it plans to build or expand at its Freeport complex, is aimed at taking advantage of cheap natural gas produced from shale, which the company expects to be available for the long term.

“There is enough responsible supply that the market will be attractive for decades to come,” Dow CEO Andrew Liveris said in an interview with the Houston Chronicle.

The four plants would create more than 4,800 jobs at their construction peaks and would support up to 600 permanent jobs, with average salaries of $75,000, when completed.

The plants would not have been viable in the United States before the boom in production of domestic fossil fuels from shale, which has flooded markets with of cheap natural gas, he said.

“If you had told me 10 years ago I’d be standing up on this podium making this announcement, I would not have believed you,” Liveris said, flanked by Gov. Rick Perry and Lt. Gov. David Dewhurst during an announcement Thursday at Brazosport College.

“Even though Texas had its great mechanisms to attract business, the cost of energy, the cost of feedstocks, which would have been the price of oil and the price of gas, was pricing the United States out of the market,” he said. But the shale “miracle” changed that.

The main attraction Thursday was Dow’s plan for an ethylene cracker that will convert natural gas and its liquid byproducts, such as propane, butane and ethane, into building blocks of plastics used in water bottles, vinyl and other items.

Others are eager

Other chemical companies also are betting on bountiful supplies of natural gas.

Chevron Phillips said this month it will build a $1 billion chemical plant at its Baytown facility, largely because of cheap natural gas liquids.

Shell is evaluating plans to build a major plant in Pennsylvania, which also would leverage cheap liquids to produce chemicals used in a broad array of products.

Liveris said natural gas would have to rise to above $10, with oil prices remaining above $100, to cause concerns about a return on its investment.

In trading Thursday on the New York Mercantile Exchange, natural gas fell 4.4 cents to $1.907 per million British thermal units.

Dow believes a substantial jump in gas prices is unlikely, unless the government allows a surge in liquefied natural gas exports or offers dramatic subsidies to encourage greater use of natural gas-fueled cars.

“There’d be a lot more than just us screaming from every corner of Washington and state legislatures that get involved with that,” Liveris said.

Keeping it at home

Liveris argued that gas should not be exported on its own but used to produce products for export at higher values.

“Why don’t we take this gas and create 15 to 20 times value added and not export it as liquid but export is as solid?” he asked.

Perry said the Texas Enterprise Fund will invest $1 million in the new Dow facility. The total is less than a tenth of 1 percent of the plant’s overall costs, but Perry said the investment played into the company’s decision to locate the plant in Texas.

“They can go everywhere in the world,” he said. “They’re not coming here just because we have great weather – in April and May. They’re not coming here just because we’ve got great music and great barbecue. They’re coming here just because they know this is the type of environment that they want to be associated with. This is the place they want to do business.”

Liveris called Texas’ partnerships with businesses an example for the nation to follow.

“I know when I get red carpet, and I know when I get red tape,” Liveris said. “And I get red carpet in the state of Texas.”

While the Texas Enterprise Fund was a small factor, the plant’s location will allow for it to be integrated easily with Dow’s existing facilities in the area, said Jim Fitterling, Dow’s president of feedstocks, energy and corporate development.

Dow, based in Midland, Mich., expanded its operations to the Texas coast 70 years ago and has maintained a strong presence ever since. The new plants will make Freeport Dow’s largest petrochemical complex and one of the world’s biggest, Liveris said.

zain.shauk@chron.com twitter.com/ZainShauk

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Argentina’s shale potential at risk

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April 14, 2012 10:27 pm by Jude Webber

Any hostile moves on YPF, the Spanish-controlled oil company, by the pro-nationalisation government in Buenos Aires could have implications that go way beyond the companies and investors at the heart of this bitter tug-of-war.

Why? Because Argentina is sitting on what geologists and energy experts widely agree is one of the world’s most attractive reserves of unconventional gas and oil – known as shale – which are trapped deep in the bedrock below ground.

Shale is potentially a very big deal indeed. It turned the US from energy importer to exporter – something that Argentina, which spent $9bn importing fuel last year, ought to take note of.

Argentina has about a third of the US shale reserves, but they are less deep (which makes them cheaper and easier to access), seams are two to three times thicker than in the US and, for now at least, Argentine shale is concentrated in the Vaca Muerta (Dead Cow) formation, rather than being spread out across the country.

So all other things being equal, shale producers should be brushing up their Spanish and heading south. Several big players – including ExxonMobil, Total and Apache – and smaller companies already have. But it is YPF which has the biggest acreage, and it estimates that as much as $250bn will be needed to develop a viable shale industry over the next decade.

No one’s pockets are that deep, so partnerships are the way to go. Except that regulatory concerns are raising red flags before investors’ eyes now.

YPF has been publicly criticised, stripped of a string of concessions after being accused of underinvestment and now the government is analysing how to give the Argentine state a bigger role in the company – something that, according to some proposals circulating in the government, could translate into the expropriation of as much as 50.01 per cent of the company.YPF is currently controlled by Repsol of Spain, which has 57.43 per cent, and 25.46 per cent is in the hands of the Eskenazi family’s Petersen Group. Just over 17 per cent is traded on stock markets.

So enthusiasm among potential new players in the shale sector – where some were prepared to invest as much as $10,000 to $12,000 per hectare, according to industry sources – is screeching to a halt. “This is damaging shale (prospects), of course,” Alieto Guadagni, a former energy secretary, told beyondbrics.

The government has been berating YPF for what it perceives as a failure to invest enough, yet the concerns its nationalization dream are raising risks reducing investor appetite – which is perverse. And if concerns over contracts were not enough to dampen investors’ spirits, the prospect of partnering with a state that likes fast results and dislikes repatriation of dividends may give pause for thought.

What is worse is that the shale prospects represent energy that Argentina badly needs. Underinvestment in the sector, analysts and industry players say, is the direct result of a regulatory regime that keeps prices in Argentina well below the international market.

As Guadagni put it, Argentina pays domestic gas producers some $2.8 per million British Thermal Units, yet shells out some $11 per million BTU for gas from Bolivia (produced, ironically, by Repsol YPF), and some $17 for liquefied natural gas to plug its huge energy deficit.

Meanwhile, the cost to Argentines for their domestic gas is about 50 US cents per million BTU of gas, and drivers of vehicles that run on compressed natural gas pay around $1.

“The big question is whether these plans for YPF will improve or worsen Argentina’s prospects for recovering its energy self-sufficiency,” Guadagni said.

Argentina had a $3bn energy surplus in 2006. This year, Guadagni reckons the deficit will be $6bn to $7bn, ballooning to $12bn in 2013. Argentina’s policy of cheap domestic energy to stoke demand and economic growth worked well after the country’s default of nearly $100bn in 2001. But it isn’t working now.

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Europe Needs a Roadmap for Unconventional Gas

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As the unconventional gas “revolution” was quietly unfolding in the United States, its potential to transform the U.S. gas market, and the country’s national energy discourse, was not apparent until recently. It has now become clear that shale gas development is perhaps the biggest energy sector innovation for the United States in recent decades. For Europe, however, the role shale gas will play in transforming energy markets is far from certain. The old continent’s unconventional gas reserves are substantial, but the question is how fast and to what extent Europe will develop them.

Europe needs a clear roadmap for the prospects of unconventional gas in its energy future. The current situation calls for an approach that is based on realistic expectations about the pace of shale gas development, as well as a strategy that is well-informed about potential costs and benefits. Continuing uncertainty could not only hamper the flow of investment into potential unconventional gas reserves, but could also impede the development of informed plans about Europe’s energy security and ability to fight climate change.

To begin with, it is worth recognizing Europe’s limitations. The combination of factors that led to the unconventional gas “revolution” in the United States—favorable geology, developed gas markets, and until recently, limited regulatory and public constraints—is not easy to replicate. Geologically, knowledge of unconventional gas in Europe does not go much beyond rough estimates. Where exactly are the shale deposits located? At what depth? And in what type of formations? At what cost could they be extracted? Europe still needs to start mapping out its shale gas reserves—a process that started almost three decades ago in the United States. At this point all that is known is that there are sufficient reserves to transform Europe’s gas market. Estimates vary but they consistently put the European Union’s unconventional reserves well above its conventional ones. Knowing this alone, however, is not enough.

The cost of developing shale gas reserves will be a principal factor in determining the future of unconventional gas in Europe. The sharp growth in shale gas output in the United States owes much to the considerable cost reduction witnessed over the past decades. Europe stands at the beginning of that process. Lack of comprehensive geological knowledge about shale precludes a precise estimate, though costs are expected to be high not least because of the scattered nature of reserves in Europe. The absence of a vibrant services sector for the gas market presents another bottleneck. The European gas sector’s limited capacity to provide cost-effective equipment for shale gas development along with a shortage of qualified labor will undoubtedly lead to higher development costs than in the United States. Costs can certainly go down, just like they did in the United States, as the industry gradually reacts to the needs of the market. But initial costs will pose a challenge.

In its quiet “revolution,” America’s unconventional gas industry outpaced both the regulators and the public. By the time stringent environmental demands became part of the national energy discourse, unconventional gas had already assumed its transformative role in the U.S. gas sector.

In Europe, if this revolution is ever to be repeated, it will not be a quiet one. The rigorous environmental regulations that are already in place—particularly with regard to water use—are prompting investors to think twice about managing costs before they commit. With their high population density, many European governments are less willing to embrace shale gas before its environmental impacts become apparent. In many countries, particularly in Western Europe, governments ignore environmental movements at their own peril. More investment in shale development will almost certainly have to confront calls for even stricter ecological requirements.

The EU’s energy and climate policy needs to recognize these constraints. It would be unrealistic to expect shale gas to be a panacea for the Union’s growing concerns on energy security and climate mitigation. This is true at least in the short and medium term.

And yet, discounting the potential role of unconventional gas in Europe’s future would be a mistake. It is in the EU’s long-term interest to maintain a role for shale gas development. Most industry insiders argue that unconventional gas will not contribute in any significant form to Europe’s energy supply until at least the end of this decade. Its role beyond that point, however, is anyone’s guess. How fast Europe develops these resources depends on today’s policy choices.

European policymakers should give shale gas development a chance. First, as a latecomer compared to the United States, Europe is more likely to find a way to develop its unconventional resources in an environmentally friendly fashion. Stricter regulations and low public tolerance for potential environmental risks may slow the pace of shale gas development. They can, however, also ensure that Europe develops these resources in the right way, avoiding some of the mistakes witnessed in America.

Second, the benefits of shale gas development could be disproportionately large. European gas supplies are in decline, while demand is expected to continue to grow. The EU’s ever growing need for imported gas is compounded by its dependence on a rather small number of external suppliers—Russia, Norway, and Algeria account for nearly three quarters of Europe’s imports. It is not certain that unconventional gas can reverse the decline in domestic gas output. However, it could certainly enhance the position of European importers when bargaining with their limited number of suppliers. Most recently, gas sold at spot markets, which constitutes only a fraction of total gas imports in Europe, effectively served such a role. Even Gazprom, known for its firm bargaining position, felt the need to revise a portion of its contracts. Shale gas could play a similar role for European importers in the future by enhancing competition. Increased liquefied natural gas (LNG) imports could potentially have a similar impact. But, they will be need to be sourced from outside the EU, maintaining Europe’s dependence on global LNG market trends.

Even if unconventional gas is not a “game changer” for Europe as a whole, it could be a “game changer” for a select group of EU members. Ironically, some of the countries with greater prospects for shale gas development—Poland, Hungary, and Bulgaria—are among the most dependent on Russian gas.

At this point, the future of shale gas in Europe is very much in the hands of national governments. Legal competence for hydrocarbon development is mainly within the domain of these governments rather than Brussels. What they need is a well-informed national discourse on unconventional gas that involves all the main stakeholders. In effect, they need to avoid what France recently did—a rushed decision outlawing hydraulic fracturing—and instead attempt to fully assess the potential for developing shale gas while complying with strict environmental standards.

Brussels, on the other hand, does have a role to play. In addition to ensuring higher environmental standards, it could attempt to bring greater clarity about the future of natural gas in Europe’s energy balance. Mixed signals about its expected role have understandably preoccupied investors. Also, it could elaborate investment mechanisms for shale gas development that would serve its long-term decarbonization objectives by displacing more carbon-intensive sources of energy. Ultimately, Brussels should make certain that Europe does not miss this opportunity to seize the strategic potential offered by unconventional gas.

Adnan Vatansever is a senior associate in the Energy and Climate Program at the Carnegie Endowment. This article was originally published on Carnegie Europe’s website

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Repsol YPF ups Argentine shale potential

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Posted on February 8, 2012 at 6:08 pm by Associated Press

SANTIAGO, ChileRepsol YPF on Wednesday raised the estimate for potentially recoverable oil and gas in its part of Argentina’s “Vaca Muerta” (Dead Cow) basin to the equivalent of nearly 23 billion barrels, indicating a total shale deposit big enough to enable Argentina to challenge the United States in non-conventional petroleum production.

But it cautioned that exploiting the formation would need a huge expansion in Argentina’s oil and gas industry, requiring thousands of wells, hundreds of drilling rigs and a national push to attract the necessary talent, equipment and investment at a time when other countries are competing to increase energy resources.

The company’s shares traded on the Buenos Aires stock exchange jumped 8 percent after the announcement.

Repsol YPF SA, a majority-Spanish-owned company, issued the statement from Madrid shortly after its president, Antonio Brufau, returned from a series of closed-door meetings in Argentina with government officials who have been pressuring the company to increase exploration and development.

The pro-government newspaper Pagina12 in Buenos Aires said Repsol YPF has been paying out more in dividends than it has made in profits in Argentina, and suggested President Cristina Fernandez might consider nationalizing the company’s Argentine operations so the money could instead be used to increase Argentina’s energy capacity.

Juliette Kerr, a Latin America energy analyst at IHS in London, discounted the possibility of nationalization, saying Argentina can’t afford a buyout. The idea was never openly endorsed by Fernandez or her Cabinet ministers.

Company spokesmen and government officials declined to comment on the talks this week.
But Wednesday’s statement, made as a filing to Spain’s securities regulator, provided a stark analysis of Repsol YPF’s commitment to Argentina and how much would have to change for the country to realize its energy dreams.

“If exploration proves successful in the Vaca Muerta formation and immediate intensive development began in the area, in 10 years its capacity could double Argentina’s existing gas and oil production. This would require a vast investing effort that would reach $25 billion per year in order to develop all the existing prospective resources,” it said.

Repsol YPF said in November that it had discovered 927 million barrels of recoverable oil and natural gas in the shale deposit. But even 23 billion barrels ranks below Brazil’s recent deep-sea oil discoveries, which experts estimated at up to 55 billion barrels, or the 296 billion barrels of proven crude reserves that Venezuela claims.

Argentina currently has only 80 drilling rigs and would need at least 100 more, along with upgrades in all sectors of its oil and gas industry, to capitalize on the potential of the deposit in western Neuquen province, the company said.

Repsol YPF currently is the leader in exploring in this area, having invested $300 million in exploration, mapping and initial development, but has claims on less than half of the formation, which stretches over 7.4 million acres. Many other companies would need to make substantial investments for the area to achieve its potential, it said.

So far, only a tiny fraction of the Vaca Muerta foundation has been developed, producing 700,000 barrels as of December, and the statement suggested that Brufau didn’t give in to the pressure for huge new investments right away.

“The company aims to drill 20 wells in 2012, solely and jointly with several partners, to continue investigating prospective resources,” it said.

The statement suggested international investors may be holding back until they have confidence that Argentina will guarantee government policies and labor unrest won’t get in the way of eventual profits. Instead, Argentina has been withdrawing energy exploration subsidies, dealing with a punishing oil workers strike and making it more difficult for multinational companies to move their gains out of the country.

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Everything You Need To Know About The Shale Gas Revolution

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Mamta Badkar

There has been a surge in domestic energy production in 2011, and a large part of it has been attributed to the shale boom. In fact, the U.S. has twice as much natural gas as Saudi Arabia has oil.

Shale gas is touted as a cleaner for of energy, and with its contribution to the economy, those in favor of recovering these resources argue that it would cut American and global dependence on OPEC.

Yet ‘fracking,’ a crucial part of shale gas extraction, is considered dangerous and many fear its impact on the environment. In the EU, member states are diverging significantly in national policy responses to shale gas regulation.

Where does shale come from? How can you cash-in on the shale boom? Why is fracking so controversial? A report from UK think tank The Global Warming Policy Foundation gives us a quick breakdown of everything you need to know about shale gas market.

Click here to see how shale gas works >

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