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trysail said:


Methane hydrate again ?


As long as I live, I'll never forget the response of a Mobil geologist to a question about natural gas sufficiency. His response was brief and simple: "The reason the world's round is because it's full of gas."


That was in, oh, say 1989-ish or thereabouts.
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Methane, indeed. More likely from decay.
 
http://www.bloomberg.com/news/2012-05-21/shale-glut-means-1-a-gallon-savings-at-the-pump.html



Shale Glut Means $1-a-Gallon Savings at the Pump
By Eduard Gismatullin and Jeremy van Loon
May 21, 2012

Chad Porter wants to run his 18- wheeler trucks on frozen natural gas along a highway that crosses Canada’s Rocky mountains even before the world’s longest chain of refueling stations gets built to keep them fueled.

The chief operating officer of oil services company Ferus Inc. bought two vehicles to test liquefied natural gas and reckons switching from diesel may cut 22 percent from his fuel bill, or about $1 a gallon. At the moment, Calgary-based Ferus uses mobile tankers to refuel his trucks, which cost about C$100,000 ($99,000) more than conventional vehicles, adding expense to a project that’s about saving money. A Royal Dutch Shell Plc project will make it easier to fill up.

Shell’s plan to spend $250 million on an LNG plant and a string of filling stations is the biggest single investment yet in making frozen gas a transport fuel, a shift advocated by proponents of energy independence including billionaire investor T. Boone Pickens. Switching engines to run on LNG is becoming economic because a glut of fuel from North America’s shale rocks has made the U.S. the world’s largest natural-gas producer and forced prices to record discounts versus crude oil.

“LNG holds great potential as a transport fuel,” Mark Williams, Shell’s director for downstream, said in a speech this month. “North America, for example, now has a century of gas supplies at current consumption rates. So gas is likely to gain market share in transportation.”

Special Coolers
Using LNG in vehicles has limitations, from fuel evaporation to the special coolers needed at filling stations to keep the gas at minus 162 degrees Celsius (minus 259 Fahrenheit), making it mostly suitable for long-haul trucks with large gas tanks. U.S. truckers spent more than $135 billion on fuel last year, according to American Trucking Association.

“We would take advantage of any infrastructure that gets built,” Ferus’s Porter said in an interview from his office in Calgary.

Shell agreed to work with filling-station owners Flying J Inc. to offer LNG to trucks along the highway, from Fort McMurray in Alberta, the heart of Canada’s oil industry, to Vancouver on the Pacific coast, more than 900 miles (1,600 kilometers) to the southwest. At today’s diesel prices, fuel for each run on the route by a typical 33,000-pound, 60-foot truck costs about C$550.

The roadway, which comes within about 235 miles of Mt. Robson, the range’s highest peak at 12,972 feet, passes through part of Canada’s oil and gas producing region, as well as the mining and forestry operations of companies including Teck Resources Ltd. (TCK/B)

‘See Opportunities’
“We see opportunities for a concept like this one in other areas of the world as well,” said Jose-Alberto Lima, Shell’s vice president for LNG and gas sales in Americas. He said Shell, based in The Hague in the Netherlands, doesn’t expect a rebound in gas prices anytime soon.

In addition to being cheaper, natural gas burned in trucks emits as much as 25 percent less carbon dioxide, as well as almost eliminating particulate matter and sulfur dioxide produced by diesel-powered vehicles, according to the Calgary- based Van Horne Institute. Using natural gas, a fuel where North America is self-sufficient, would also cut demand for imported crude oil.

Shell eventually plans to deploy LNG technology to power trains, ships and mining industry engines. Gas overtook crude oil to account for more than 50 percent of the company’s production for the first time this year. It expects to expand the use of LNG as a transport fuel beyond North America to Europe, China, Latin America and Australia.

Green Corridor
The Anglo-Dutch company’s Green Corridor project in Canada will make 300,000 tons of LNG a year. It plans to start production at its first small-scale gas liquefaction plant at Jumping Pound near the route’s halfway point next year.

“These trucks are more expensive than the traditional diesel trucks today,” Shell’s Lima said. “You need to have economies of scale to bring these costs down.”

Shell is cooperating with Vancouver-based Westport Innovations Inc., the maker of cryogenic fuel tanks and the only currently available 15-liter gas-powered engine suitable for heavy-duty trucks running on LNG.

Compressed Gas
The second Canadian maker of gas powered engines is Cummins Westport Inc., which makes smaller 8.9 liter heavy-duty unit. The Vancouver-based joint venture of U.S.’s Cummins Inc. (CMI) and Westport has designed a motor able to run on either compressed natural gas, CNG, or LNG.

CNG is used for light- and medium-duty vehicles, such as buses and garbage trucks. LNG, which is using a cryogenic technology to chill gas and reduce it to one-six-hundredth of its original volume at low temperature, is offered mostly as a fuel for heavy-duty vehicles.

CNG, which is stored at ambient temperature, requires tanks with thicker walls to hold the pressure and provides less energy per volume. Therefore, long-haul trucks can take more LNG on board in lighter chilled tanks with less time required for refueling per energy unit.

“Drivers have been very receptive to LNG trucks, especially since they drive like diesel trucks,” said Cara West, a spokeswoman at Paccar Inc., which designs and manufactures trucks under Kenworth, Peterbilt and DAF nameplates and where Ferus bought its vehicles. “Dealers are receiving multiple inquiries from customers anxious to learn more about LNG trucks.”

Market Share
Paccar currently equips some of its Kenworth and Peterbilt models with LNG engines. The Washington state-based maker expects the gas-powered-truck market share in North America to expand to about 20 percent in the next several years, up from about 6 percent now.

With natural gas fuel taxed about 20 Canadian cents less a liter than diesel on equivalent basis, it takes less than five years for a driver to return extra investment benefiting from cheaper fuel, according to the Canadian Natural Gas Vehicle Alliance. Canada has more than 100 LNG powered trucks almost equally split between western and eastern parts of the country operated by Vedder Transport, a milk hauler in British Columbia, and Robert Transport, which operates in Quebec and is expanding the fleet.

In January, President Barack Obama said tax breaks for natural-gas powered trucks will help cut dependence on imported oil in the world’s largest crude-consuming country. “We, it turns out, are the Saudi Arabia of natural gas,” Obama said. The U.S Senate and House have been reviewing the bill to boost greater use of the gas.

Huge Resource
“The potential is there, and when you have this huge resource in the U.S., and you’ve got almost 10 million barrels per day imported being used for transportation fuels,” said Theepan Jothilingam, an analyst at Nomura Holdings Inc. At some stage, the U.S. government “will need to give a tax break and encourage both the technology and the execution of this technology.”

Billionaire investor Pickens has been lobbying for incentives to stimulate greater use of natural gas as a vehicle fuel to replace imported oil. Pickens is the largest shareholder of Clean Energy Fuels, a natural-gas supplier for bus and truck fleets, which is building America’s Natural Gas Highway across the U.S. to fuel long-haul trucks with LNG starting from the end of this year.

About 30 percent of U.S. “classic trucks” can be converted to run on LNG, which needs highly utilized vehicles running lots of miles to pay back for the additional engine costs by fueling it with cheaper LNG, said James Burns, Shell’s general manager for LNG in Transport, Americas. “Emissions is a key issue here as well both on local air emissions and green- house gas emissions.”


http://www.bloomberg.com/news/2012-05-21/shale-glut-means-1-a-gallon-savings-at-the-pump.html
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http://www.reuters.com/article/2012...4?feedType=RSS&feedName=rbssEnergyNews&rpc=43



Repsol-led group makes big oil find off Brazil

* Discovery could draw more explorers to hot region

* Brazil eyeing becoming world no.3 crude producer

* Brazil key area for Repsol after Argentina nationalisation

By Paul Day and Balazs Koranyi

MADRID/OSLO, May 24 (Reuters) - Spanish oil firm Repsol confirmed a large oil and gas find off Brazil on Thursday in a discovery that is likely to attract more explorers to one of the world's hottest regions for oil and gas drilling.

Repsol, in partnership with China's Sinopec , Norway's Statoil and Brazil's Petrobras , said the discovery in the Campos basin could hold over 1.2 billion barrels of oil equivalent, a figure that equals more than Brazil's expected total oil output for this year.

"This is quite a large find for Brazil and like all big finds, it's going to encourage firms that have expertise in deepwater drilling to invest there," said DNB oil market analyst Torbjoern Kjus.

Brazil is key to Repsol's Latin American explorations after Argentina announced in April that it would nationalise the company's Argentine unit YPF.

The Brazilian discovery, which includes over 700 million barrels of recoverable crude oil and 3 trillion cubic feet of natural gas, could result in peak production of about 300,000 barrels per day, Kjus added.

The firms did not provide further detail on development plans but Statoil exploration chief Tim Dodson said production was unlikely to start before 2020.

"It's a very good reservoir and it is light oil, so I think it is appropriate for a good production rate," Dodson said, adding it was too early to provide more specific plans.

Oil firms in Brazil such as Petrobras, Royal Dutch Shell and Chevron, are expected to produce more than 8 million barrels of oil equivalent a day by 2020, an amount that could allow Brazil to surpass the United States as the world's No. 3 oil producer after Russia and Saudi Arabia.

Most of that oil is expected to come from giant, deep-water oil fields off Brazil's coast near Rio de Janeiro and Sao Paulo, including the Campos Basin, home to several billion-barrel-plus fields and some of the world's largest discoveries in the last 30 years.

The country's main offshore regions, the Campos Santos Basins, contain as much as 100 billion barrels of oil, according to the Brazilian Petroleum Institute at the State University of Rio de Janeiro.

That would be enough to supply all of the needs of the United States, the largest consumer, for about 14 years, according to BP and Reuters calculation.


HIGH COST RISK

The discovery, in so-called pre-salt blocks, also improves prospects for exploration off Angola, on the other side of the Atlantic, as the two areas have similar geology.

Still, analysts warned that the nature of the discovery make production uncertain given how high production costs in such extreme circumstances can rise.

"These barrels will be among the most expensive to produce and if onshore discoveries become more abundant, these will simply not get developed," DNB's Kjus said.

Oil firms have been increasingly investing into developing onshore shale liquids and if efforts succeed, firms would be able to reduce costs.

"These shale fields can have break-even costs at around $50 while deepwater costs can be as much as $100 per barrel," Kjus said.

Repsol Sinopec Brasil, a joint venture between Repsol and Sinopec, is operator of the latest discovery and holds 35 percent while Statoil has 35 percent and Petrobras has 30 percent.

The consortium is currently preparing an appraisal plan to be presented to the Brazilian National Agency of Petroleum, Natural Gas and Biofuels (ANP).



http://www.reuters.com/article/2012...4?feedType=RSS&feedName=rbssEnergyNews&rpc=43
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http://www.bloomberg.com/news/2012-...udis-for-largest-oil-reserves-bp-says-1-.html



Venezuela Overtakes Saudis for Largest Oil Reserves, BP Says
By Rupert Rowling
June 13, 2012

Venezuela now holds the largest proven oil reserves in the world, overtaking Saudi Arabia, according to BP Plc.

The South American country’s deposits were at 296.5 billion barrels at the end of last year, surpassing Saudi Arabia’s 265.4 billion barrels, BP said today in its annual Statistical Review of World Energy. The 2010 estimate for Venezuela was revised to the same amount, up from 211.2 billion in the previous report.

Global reserves advanced to 1.65 trillion barrels at the end of last year, a 1.9 percent increase from a revised 1.62 trillion in 2010, BP said. North Sea Brent crude, a benchmark for more than half of the world’s oil, averaged $107.38 a barrel in 2011, according to data compiled by Bloomberg.

One reason for the revisions is that the company publishes its report in June, before most governments issue their annual reserves figures, said Robert Wine, a BP spokesman. Last year’s record average oil price also had an effect, increasing the commercial viability of hard-to-reach deposits, he said.

Venezuelan reserves account for 17.9 percent of the global total, with Saudi Arabia’s share at 16.1 percent, according to the report. Canada ranks third with 175.2 billion barrels, or 10.6 percent of the worldwide total, unchanged from the revised number for 2010.

Doubling Capacity
Hugo Chavez, Venezuela’s president, will more than double the country’s oil-production capacity to 6 million barrels a day by 2019 if re-elected on Oct. 7, according to a government plan released yesterday on his website.

Russia, the world’s biggest crude producer, boosted its deposits to 88.2 billion barrels from a revised 86.6 billion a year earlier, according to BP. Russia’s share of the total is 5.3 percent. Brazil’s share rose 7.3 percent to 15.1 billion barrels, BP said.

Reserves in Norway increased last year, snapping 11 years of decline, according to BP. The country’s deposits rose to 6.9 billion barrels, compared with a revised figure of 6.8 billion in 2010.

BP said the estimates in today’s report are a combination of official sources, OPEC data and other third-party estimates. Deposits include gas condensates and natural-gas liquids, as well as crude.



http://www.bloomberg.com/news/2012-...udis-for-largest-oil-reserves-bp-says-1-.html
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I am not an old "cold warrior" (see the article below) though I confess to being fascinated by some of the similarities of energy market dynamics to aspects of the 19th century "Great Game" of competing British and Russian interests in South Asia. Make no mistake, there are titanic forces at work here.

It is also a classic example of the dynamism and power of market prices to allocate capital.

Gazprom's gargantuan reserves of natural gas (on an energy equivalent basis, Gazprom's hydrocarbon reserves are at least 4× those of ExxonMobil) were particularly eye-catching when natural gas prices in the U.S. peaked at ~$13ish/Mcf in 2006-8.

Unlike petroleum, the market for natural gas is fragmented by limitations of infrastructure. A pipeline is, essentially— and by far, the easiest and most efficient way to deliver natural gas. Large quantities of known reserves of natural gas have little current economic value because there is no pipeline to get the natural gas to consumers. A prime example of this is the "stranded" natural gas in Prudhoe Bay, Alaska.

This leads to large regional price differentials that makes capitalists drool over the arbitrage potential. While natural gas in the U.S. is available for ~$2.60/Mcf, LNG cargoes to Japan fetch the equivalent of $12-14/Mcf since LNG markets are accomodated by multi-year supply contracts with prices based on petroleum ( one barrel of petroleum is the energy equivalent of 6 Mcf of natural gas ).

In turn, the current yawning disparity between contract-based LNG prices and spot natural gas is also attributable to the historically unprecedented difference between petroleum and natural gas prices.


Petroleum price (WTI) vs. Spot natural gas price:

http://alfred.stlouisfed.org/alfredgraph.png?g=8bi

U.S. natural gas prices:

http://alfred.stlouisfed.org/alfredgraph.png?g=8bj​

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http://www.bloomberg.com/news/2012-...-loser-as-shale-gas-upends-world-markets.html



Gazprom Biggest Loser as Shale Gas Upends World Markets
By Anna Shiryaevskaya
June 22, 2012

The natural-gas boom reshaping America is rocking Russia, where state producer OAO Gazprom is slow to react and at risk of becoming the world’s biggest loser from the new technology to drill shale rock.

The U.S. no longer needs Russia’s gas, leaving President Vladimir Putin fighting to salvage Gazprom’s $20 billion Shtokman project in the Arctic. China, the biggest energy consumer, is exploring its own shale reserves and hesitating to accept a pipeline from Russia. Gazprom’s shipments fell about 14 percent so far in 2012, and the stock has lost 9.5 percent.

Russia, with about $13 trillion of gas deposits, has the most at stake in the energy revolution that’s blasting shale from Pennsylvania to China in rocks impossible to drill just a decade ago. While Gazprom remains the gas biggest producer, the export monopoly is set for its toughest market since the Soviet Union’s fall in 1991 after letting rivals like Exxon Mobil Corp. take the lead in a technology that’s eroding its sales.

“Gazprom is taking what seems to be a ‘head in the sands’ position on shale gas,” said Andy Flower, a former BP Plc executive who’s now a consultant on the global gas market based in Surrey, England.

Putin in April urged Russia’s energy companies to “rise to the challenge” of shale. Afterward he coaxed partners in the Arctic Shtokman project to move forward, in comments before the start of this week’s St. Petersburg Forum of global executives. Gazprom Chief Executive Officer Alexey Miller yesterday held talks there with chiefs of France’s Total SA and Statoil ASA of Norway as the partners in the Shtokman project aim to reach a new shareholder accord and decide on its fate by month’s end. Total and Statoil hold 49 percent of the project.

Hits Growth
Gazprom “will take some pain to adjust” to the shale-gas revolution, said Ben Montalbano, a senior research analyst at Energy Policy Research Foundation in Washington. “It hits production growth prospects, pricing power and revenues.”

The Moscow-based company’s earnings per share will drop 10 percent in 2012 to 56.9 rubles, according to analyst estimates compiled by Bloomberg. That contrasts with a 6.3 percent median gain among 63 oil and gas producers on the Bloomberg World Oil & Gas index. Gazprom shares have fallen 57 percent since reaching a record high in 2008, while the index lost 41 percent.

The stock dropped as much 1.6 percent to 153.56 rubles in Moscow trading today.

Gazprom downplays the threat from shale on global gas markets, saying European demand will hold up and the collapse in U.S. prices caused by a glut is temporary.

Shale Gift
“Shale gas is a gift for the entire gas industry, because it effectively removed a question of potential depletion of reserves,” Sergei Komlev, head of pricing at Gazprom’s export unit, said in an e-mail. “But a common view that shale gas is cheap is wrong.”

Should Gazprom founder, Russia could follow. With most of its contract prices pegged to oil, which has fallen about 15 percent this year, its profit outlook weakened.

Last year, Russia’s largest company boosted sales 29 percent to a record 4.6 trillion rubles ($141 billion), as benchmark Brent oil prices climbed 13 percent. It led oil and gas companies in providing about half of state revenue. This year sales are forecast to climb 6 percent.

Forged from the Soviet Union’s gas ministry after the collapse of the communist regime in 1991, Gazprom has been accused of carrying out government policy in using its supplies to assert Russian power. Shipments to neighboring Ukraine were repeatedly halted since 2006 in disputes over energy prices. Russia holds the world’s biggest reserves, equal to 21 percent of all known deposits.

Overtake Russia
Shale production allowed the U.S. to overtake Russia as the largest gas-producing nation in 2009 after explorers began employing hydraulic fracturing, a technique using pressurized water with chemicals and sand to open cracks in rock for freeing gas.

The subsequent collapse in prices, which touched a 10-year low in New York in April, killed the U.S. as an export market for Shtokman and other liquefied natural gas projects. The U.S. will even become a gas exporter as early as 2015.

Gazprom can’t look to Europe for relief. It supplies about 25 percent of gas demand by pipeline, though the market is shrinking as the economic crisis undermines demand. Shipments are down 14 percent this year.

Nations dependent on Russian gas, such as Ukraine and Poland, are starting to assess their own shale gas potential.

“There is always the possibility that the shale gas revolution may, in the long run, produce less gas than some are now forecasting, but I think the probability is very low,” Flower said.

Strategic Challenges
Shale gas output in China and the U.S., and to a lesser extent Europe, “creates strategic challenges for existing gas exporters,” the International Energy Agency said in a report on May 29. The share of Russian and Middle Eastern producers in the international gas trade may decline to 35 percent in 2035 from about 45 percent in 2010, the IEA said in a report on unconventional gas.

Gazprom’s weakening position undermines its ability to link gas-export prices to oil, a device that’s kept prices in Europe above U.S. levels. Under pressure, the company agreed to price discounts to some customers, such as GDF Suez SA and Eni SpA, while pursuing arbitration and talks with EON AG and RWE AG’s units and Poland’s PGNiG earlier this year.

“It will take several years before we know the full potential of European and Chinese shale, but if either one even partially pans out, it will significantly reduce demand for Gazprom gas, particularly at oil-linked prices,” Montalbano said.

More Sanguine
The company still expects volumes to Europe to remain unchanged this year and revenue supported by higher oil prices. Gazprom estimates its export revenue from sales to Europe will still increase this year to $61 billion from $57 billion last year, only approaching the record $64 billion in the pre-crisis 2008, Deputy Chief Executive Officer Alexander Medvedev said on June 20.

Still, the transformation of the global gas market has already pushed Gazprom to delay the Shtokman project in the Arctic, which was expected to ship 90 percent of fuel to the U.S. Meanwhile, rival exporters Qatar and Australia have expanded export capacity to allow them to ship fuel to Asia, which has the highest gas prices in the world.

Gazprom is trying to switch its strategy to produce more LNG for shipping to Asia, Medvedev said in Kuala Lumpur earlier this month. It plans to expand the Sakhalin export plant in Russia’s Far East and still expects Shtokman to succeed with customers outside the U.S., he said.



http://www.bloomberg.com/news/2012-...-loser-as-shale-gas-upends-world-markets.html
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http://www.bloomberg.com/news/2012-...h-finds-u-s-shy-in-icebreakers-energy-1-.html



Shell-Led Arctic Push Finds U.S. Shy in Icebreakers
By Carol Wolf and Kasia Klimasinska
Juyl 18, 2012

Royal Dutch Shell Plc has spent $4.5 billion since 2005 preparing to explore for oil off Alaska’s north coast in the Arctic. U.S. taxpayers may end up paying almost as much to supervise future operations in the region.

Shell, which may begin drilling next month, is one of at least six companies planning to extract oil, gas and minerals in the Arctic as global warming melts ice and opens new sea lanes to commerce. As the companies move in, so must the Coast Guard, to defend U.S. interests, perform sea rescues and coordinate the government’s response to any oil spills.

The Coast Guard is ill-equipped for the Arctic. It lacks appropriate communications and navigation systems, and will need at least $3 billion in additional vessels and equipment, assessments by the Congressional Research Service and the Coast Guard itself show. Without more icebreakers, the service will be “unable to accomplish its Arctic missions,” according to a report last year by the Homeland Security Department’s inspector general.

“The Coast Guard has zero capability in the Arctic,” Admiral Robert Papp, the Coast Guard commandant, said in a July 13 interview at a Bloomberg Government breakfast in Washington. “If we are going to have a permanent presence there, it’s going to require some investment. We don’t have the infrastructure in place right now.”

Laying Plans
Countries and companies are laying plans for the Arctic, which holds about a fourth of the word’s undiscovered oil and natural gas, according to the U.S. Geological Survey. The U.S. has more than 1,000 miles of Arctic shoreline. Much of its oil is off the Alaskan North Slope, which is bordered by the Beaufort and Chukchi seas and about 1,100 miles northwest of Juneau, the state capital.

Russia in 2007 dropped a capsule containing its flag on the seabed 14,000 feet below the North Pole, staking a claim for oil and gas reserves there. Canada plans to purchase military icebreakers to protect its interests. China, which doesn’t have an Arctic border, has signed energy agreements with Iceland.

The Hague-based Shell, Europe’s biggest oil company, will be the first to resume operations in the Arctic. It was last explored in the early 1990s, before lower oil prices reduced profit prospects. Shell is awaiting final approval from the U.S. to begin drilling.

ConocoPhillips and Statoil Asa of Norway also have won rights to explore fields in the Arctic. Exxon Mobil Corp., the biggest energy company by market value, has reached an agreement with Russia to explore its area of Arctic. Other companies with plans for the region include BP Plc, Imperial Oil Ltd. and Chevron Corp.

Icebreakers Critical
Even as ice recedes, the Arctic remains a vast frozen area with hurricane-strength storms, below-freezing temperatures and large ice floes, making icebreakers critical.

“Even with the open sea lanes, the Arctic is immensely dangerous,” Peter Harrison, director of the school of policy studies at Queen’s University in Ontario, whose work focuses on the Arctic, said at a Brookings Institution conference on the subject last month. “If anyone thinks it’s like Lake Michigan in July and August, they are dreaming in Technicolor.”

Papp said the Coast Guard eventually would need three heavy-duty and three medium-duty icebreakers for the Arctic. It now has one medium-duty icebreaker and two heavy-duty ones dating from the 1970s, neither of which is currently operable. The service plans to repair one of them.

That means the U.S. would need to build four icebreakers -- two heavy-duty and two medium-duty -- with an estimated total cost of $3.2 billion, according to a Congressional Research Service report in April.

‘Pay Attention’
Neither Congress nor the administration of President Barack Obama has proposed spending that kind of money on icebreakers. The Obama fiscal 2013 budget has called for $8 million to study building one. The Coast Guard’s five-year plan has called for $852 million for its actual construction in subsequent years, although Congress has yet to address the funding. It can take as long as 10 years to build an icebreaker.

Russia has 25 icebreakers, which are being used “to assert sovereign control over the Arctic region and its valuable resources,” according to the Congressional Research Service report.

Finland and Sweden have seven icebreakers each and Canada has six, the report says. China has one icebreaker and another under construction.

Exercises Beginning
“This is an internationally competitive area where we must start paying attention,” Representative David Price, a North Carolina Democrat and ranking member of a House Appropriations subcommittee in charge of allocating the money, said in a telephone interview. “The Coast Guard is going to be called on to do a lot of things up there and we can’t limp along with our current icebreaker capacity.”

For the Shell drilling, the Coast Guard plans to send two helicopters and two cutters to the Arctic, including one of its three flagship National Security Cutters.

The Coast Guard opened a temporary base in Barrow, Alaska, on July 16. It will practice oil-spill responses as well as other maneuvers to test equipment and personnel readiness, said Vice Admiral Peter Neffenger, deputy commandant for operations at the service, in a telephone interview.

“Our goal is to have a presence up there that can adequately address the activity for this summer and then to think about what it means for the future,” he said.

The ships and equipment will have to be pulled from Coast Guard duties elsewhere, Commandant Papp said.

No More Resources
“The problem with that is no one is giving me any additional resources to take on this new mission,” Papp said in the interview. The cutter in the Arctic is “not going to be able to do drug interdiction in the eastern Pacific on the drug routes from South America. We’re going to have to pull other ships off fishery patrols in the western Pacific from a Naval exercise in the western Pacific.”

Placing a National Security Cutter in the Arctic will help because the ship can function as an air station and communications center, and has three boats for rescue missions and security operations, he said.

“It gives us immediate capabilities and infrastructure in the summer, and when the ice starts forming we can pull it back,” Papp said.

Shell’s Preparation
The U.S. plan to oversee the drilling is inadequate and favors Shell at the expense of taxpayers, said Michael Conathan, director of Ocean Policy at the Center for American Progress, a Washington-based research firm.

“Those are not assets that were just sitting on a shelf somewhere waiting to be deployed,” Conathan said in a telephone interview. “Instead of doing other jobs, they will be babysitting Shell’s operations and the American taxpayer will be on the hook.”

Shell is bringing its own equipment for the job and emergencies, including 33 vessels and 600 workers, said Steve Phelps, Shell’s manager of exploration for Alaska.

“We know the region is very remote and very dangerous,” Phelps said at the Brookings Institution forum. “We realize if we need it, we have to bring it.”



http://www.bloomberg.com/news/2012-...h-finds-u-s-shy-in-icebreakers-energy-1-.html
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Keystone XL pipeline, anyone? The Chinese and the Canadians are laughing at the idiots in the U.S. who have played right into their hands. I guaran-damn-tee you there will be an export pipeline built to the Canadian west coast.
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http://www.bloomberg.com/news/2012-...exen-for-15-1-billion-to-expand-overseas.html



Cnooc Buys Nexen for in China’s Top Overseas Acquisition
By Aibing Guo and Jeremy van Loon
July 23, 2012

Cnooc Ltd. agreed to pay $15.1 billion in cash to acquire Canada’s Nexen Inc. in the biggest overseas takeover by a Chinese company.

China’s largest offshore oil and natural-gas explorer is paying $27.50 for each common share, a premium of 61 percent to Calgary-based Nexen’s closing price on July 20, according to its statement to the Hong Kong stock exchange yesterday. Nexen’s board recommended the deal to its shareholders...

***​

...Nexen’s oil and gas assets include production platforms in the North Sea, the Gulf of Mexico and in Nigeria, as well as oil-sands reserves at Long Lake, Alberta, where it already produces crude in a joint venture with Cnooc. Those assets produced 207,000 barrels a day in the second quarter, which would boost the Chinese company’s output by about 20 percent. About 28 percent of Nexen’s current production is in Canada...

***​

...The Nexen takeover comes as Canadian companies prepare to build new pipelines for transporting Canadian fossil fuel to Asia in an effort to reduce its dependence on the U.S. market, which has depressed prices for crude produced in Alberta’s oil sands and the Bakken in Saskatchewan.

“The political context in Canada is very good at the moment,” said Wenran Jiang, the Mactaggart Research Chair of the China Institute at the University of Alberta who advised the Alberta government on Chinese investment. “The Chinese have been careful to step up their involvement in Canada slowly. This isn’t coming out of nowhere.”

The transaction follows the Chinese company’s takeover of Nexen’s partner Opti Canada Inc. last year and the $19 billion bid for Unocal Corp. in 2005, which was blocked by political opposition in the U.S...

***​

...Nexen has been searching for a new CEO since Marvin Romanow stepped down in January amid a slumping share price and missed production targets. Nexen’s market value had plunged 60 percent before yesterday from a high of C$43.45 in June 2008 as prices fell for natural gas, which accounts for about 20 percent of output. Production growth also slowed more than the company expected because of setbacks at projects in Canada’s oil sands and in the North Sea.


Barrel Value
Cnooc will add 900 million barrels of oil equivalent reserves at $19.94 per barrel through the deal, according to a document posted to the company’s website. Cnooc plans to boost output by as much as 2.7 percent this year to the equivalent of as much as 930,000 barrels of oil a day...

***​

...Calgary will become one of Cnooc’s international headquarters and the operations hub for overseeing an additional $8 billion in assets in North and Central America. The Chinese company will also list its shares on the Toronto exchange, it said in the statement...

Canadian Appeal
Canada has become a fertile area for Chinese oil producers seeking to add oil and gas reserves to meet demand in the world’s largest energy-consuming country. After yesterday’s deal, Chinese companies will have spent about $49 billion on buying Canadian fields and oil companies... In contrast, they’ve laid down just $3.5 billion in U.S. acquisitions.

The deal will cement Cnooc’s position in Canada’s oil sands after last year’s $2.4 billion purchase of Opti Canada. When the transaction closes, Cnooc will own all of Long Lake, which plans to produce 72,000 barrels a day using steam to melt the tar-like oil out of the sands...

Reassuring Foreigners
Prime Minister Stephen Harper is seeking to assure foreign companies the country is open to investment...



http://www.bloomberg.com/news/2012-...exen-for-15-1-billion-to-expand-overseas.html
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http://www.bloomberg.com/news/2012-...adding-3-6-million-jobs-along-with-3-gdp.html



America’s Energy Seen Adding 3.6 Million Jobs Along With 3% GDP
By Asjylyn Loder
August 13, 2012


On the eastern bank of the Mississippi River, about an hour upstream from New Orleans, the outline of Nucor Corp.’s new $750 million iron-processing plant is rising between fields of sugar cane and sweet gum trees.

Surveying the facility from the road, Michael Eades, president of Ascension Economic Development Corp., says it’s part of a wave of investment lured by low natural gas prices to this stretch of Louisiana’s industrial riverfront. Companies such as Westlake Chemical Corp., Potash Corp. of Saskatchewan Inc. and Methanex Corp. have projects in the works. Ormet Corp. reopened an alumina refinery last year, bringing back 250 jobs.

“We’re just seeing an incredible amount of activity,” said Eades, who tallied $1.1 billion in new projects last year in Ascension Parish alone, where his private, nonprofit group promotes development. He expects twice that this year.

It’s a harbinger of a nationwide investment boom spreading from the oil fields of North Dakota and the Marcellus gas shale in Pennsylvania to power plants in California and chemical refiners in Texas. A surge in U.S. natural gas development has spurred $226 billion in spending plans on pipelines, storage, processing facilities and power plants, most slated for the next five years, according to Industrial Info Resources, a market- intelligence provider in Sugar Land, Texas.

U.S. energy supplies have been transformed in less than a decade, driven by advances in technology, and the economic implications are only beginning to be understood. U.S. natural gas production will expand to a record this year and oil output swelled in July to its highest point since 1999. Citigroup Inc. estimated in a March report that a “reindustrialization” of America could add as many as 3.6 million jobs by 2020 and increase the gross domestic product by as much as 3 percent.

Narrow Gains
So far, the economic benefits have been confined to states such as Louisiana, Texas and North Dakota, while the national jobless rate has stayed above 8 percent for 42 straight months in the wake of the worst recession in seven decades.

“It is definitely a positive for the economy, but one can overstate how much of a positive,” said Michael Feroli, chief U.S. economist for JPMorgan Chase & Co. Oil and gas production account for about 1 percent of gross domestic product, and will have a limited impact on the country’s unemployment, he said.

Even so, there are signs the economic gains have begun to expand beyond the oil and gas fields and that the promise of abundant, low-cost fuels will give a competitive edge to industries from steel, aluminum and automobiles to fertilizers and chemicals.

Jobs Debate
That would provide a boost to a U.S. manufacturing sector that has lost 5.12 million jobs since 2001 and become the focus of a national debate over how to revive factory employment. Manufacturers have added 532,000 jobs since January 2010 as the economy started to recover, Bureau of Labor Statistics data show.

The expansion of fossil-fuel production -- coupled with a weak economy and increased energy efficiency -- has helped the U.S. pare its crude oil imports by 17 percent since the 2005 peak, Energy Department data show. Imports in 2011 accounted for 45 percent of U.S. consumption of crude and refined products. The department predicts the share will fall to 39 percent next year, which would be the first time since 1991 that imports dropped below 40 percent of demand.

“The impact on the global petroleum market and the natural gas markets is really palpable and wildly underestimated,” said Ed Morse, head of commodities research at Citigroup Global Markets Inc. who led the team that wrote the March report. The economic activity that comes with higher energy production will boost incomes, increase consumption and create wealth, he said.

Cheaper Energy
Increased production and swelling domestic stockpiles have helped make U.S. energy cheaper than in other countries. U.S. oil futures have slid to a $20 a barrel discount to London- traded Brent, a benchmark for more than half the world’s oil. Natural gas in the U.S. fell to $1.902 per million British thermal units in April, the lowest in a decade. The fuel costs almost three times as much in the U.K. and more than five times as much in Japan.

“This is one of those rare opportunities that every country looks for and few ever get,” said Philip Verleger, a former director of the office of energy policy at the U.S. Treasury Department and founder of PKVerleger LLC, a consulting firm in Carbondale, Colorado. “This abundance of energy gives us an opportunity to rebuild our economy.”

Cycle of Growth
Verleger envisages a virtuous cycle of economic growth as producers, flush with cash from oil and gas sales, will buy more equipment and put more people to work, while low-cost energy puts cash back in consumers’ pockets, stimulating spending.

Companies plan to invest $138 billion in more than 700 natural gas storage, pipeline and processing plants in the U.S., and another $88 billion in more than 500 gas-fired power generation units, according to Joseph Govreau, vice president and editor-in-chief of Industrial Info Resources. The firm tracks projects from planning stages through construction.

The IIR estimates don’t include petrochemical and fertilizer projects, which are undergoing a revival because of the low cost of natural gas feedstock.

Cairo-based Orascom Construction Industries (OCIC) is investing $250 million restarting an ammonia and methanol plant in Beaumont, Texas. Another Orascom subsidiary may build a $1.3 billion fertilizer plant in Iowa that would create as many as 2,000 construction jobs and 165 permanent positions, according to Tina Hoffman, a spokeswoman for the Iowa Economic Development Authority.

‘Massive’ Investment
“The amount of petrochemical investment that the U.S. will have in the next 10 to 15 years is massive,” said Omar Darwazah, head of investor relations for Orascom. “Given the shale gas boom, gas prices in the U.S. are arguably more competitive than the Middle East, because you don’t have the political risk.”

Increased U.S. production has already wrought significant shifts across the energy industry. Plans for gas-import terminals, thought indispensable five years ago, have been shelved in favor of export facilities such as Cheniere Energy Inc.’s $10 billion plant in Louisiana’s Sabine Pass.

Enterprise Product Partners LP and Enbridge Inc. this year reversed the Seaway pipeline that once carried oil imports from the Gulf Coast to a storage hub in Oklahoma. Now, it carries crude produced in states such as North Dakota and Colorado to refiners in Texas and Louisiana, which process and, increasingly, export it. East Coast refiners, dependent on more expensive tankers of foreign crude, are working to develop rail links and pipelines to bring oil east.

Environmental Concern
Environmentalists say cheap fossil fuels come with a high price, including air pollution that can cause respiratory difficulties, and drinking water contamination from hydrofracturing, or fracking, in which a high-pressure stream of fluid is shot underground to crack rock and release hydrocarbons. Lower gas and oil costs have also undermined investment in power sources that produce less carbon dioxide, including wind, solar and nuclear, raising concern that climate change will accelerate.

“The state is just overjoyed at all the jobs that will be coming to Louisiana without looking at the health side effects and environmental side effects,” said Darryl Malek-Wiley, a community organizer at the Sierra Club in New Orleans.

The report from Citigroup -- “North America, the New Middle East?” -- estimated that the U.S. could become the world’s largest producer of crude and natural gas liquids such as propane by 2020, overtaking Russia and Saudi Arabia.

China Consumption
U.S. natural gas prices may eventually rise if planned export terminals increase demand for the fuel, putting domestic consumers in competition with foreign markets willing to pay more. China will drive global gas consumption higher by 2.7 percent a year through 2017, the International Energy Agency said in a June report. The U.S. already competes with global consumers for refined products such as gasoline and diesel.

Still, the promised bounty from lower prices can be seen along the highways and back roads of Ascension Parish, in the heart of Louisiana’s plantation country.

In November, cheap natural gas prices convinced Hannibal, Ohio-based Ormet to reopen the refinery that makes alumina, used in aluminum production. The facility was shuttered in 2006, said Chief Financial Officer James Riley.

In nearby St. James Parish, Nucor has begun construction on the plant that will process iron using natural gas. The product will supply its steel mills, said Katherine Miller, a spokeswoman for Charlotte, North Carolina-based Nucor. Five hundred people will be needed to build the plant and 150 will be employed there once completed, she said.

Doubling Workforce
Eades gestures toward construction trailers parked on the site where Vancouver-based Methanex said in July that it will reconstruct a plant moved from Chile, white, football field- sized domes that will store Nucor’s iron ore, and chutes that carry bauxite over the Mississippi River levy into Ormet’s rust- colored plant.

All this construction means new jobs. MMR Group, a Baton Rouge-based industry contractor, will double its workforce of 2,800 in the next two years, said Grady Saucier, vice president of marketing.

A five-minute drive from MMR’s offices in Ascension Parish, Associated Builders & Contractors, a trade group, can’t keep up with demand for its training program for would-be electricians, pipefitters and welders. Steven Allen graduated from the school’s pipefitting certification program this year. Now, he earns as much as $28 an hour working in petrochemical plants, up from the $9 an hour he made as a construction laborer.

Family Struggle
“Being a laborer and a helper isn’t going to cut it when you’ve got a family to support,” said Allen, 30, a father of 6- year-old twins.

Smaller businesses, including valve manufacturers, electric-motor companies and rental lots packed with heavy equipment, also feed off the boom, Eades says. One company, Rain for Rent, provides fake downpours seen on movie sets -- as well as storage tanks and water pumps to the petrochemical industry.

Closer to Interstate 10, which connects New Orleans to Baton Rouge, a TownePlace Suites by Marriott and a Holiday Inn Express have opened in the past year next to an outlet mall and a Cabela’s outfitters store, all benefiting from the influx of new workers to the region, Eades said.

“If you have gas prices in the U.S. that are substantially cheaper than Europe or Asia, it has to have a substantial impact,” said James Brick, an analyst in Houston with Wood Mackenzie, an energy and metals researcher. “The question we’re now asking is, ‘Is this the tip of the iceberg?’”




http://www.bloomberg.com/news/2012-...adding-3-6-million-jobs-along-with-3-gdp.html
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There will be a field day for politicos— and, with good reason— if a Chinese company purchases any of these fields.

The only people "Jim Bob" Moffett has ever enriched are himself and the investment bankers. You do not want to be a minority shareholder in any company connected to ole "Jim Bob."


_____________________

http://www.bloomberg.com/news/2012-...l-drillers-in-u-s-gulf-seen-with-bp-sale.html



Asia-Pacific Oil Drillers in U.S. Gulf Seen With BP Sale
By Joe Carroll, Aibing Guo and James Paton
August 21, 2012

BP Plc’s plans to sell almost $8 billion of deep-water oilfields in the Gulf of Mexico is paving the way for the biggest influx of Asian-Pacific cash into offshore U.S. energy exploration.

Energy companies eager to hone their skills in advanced drilling techniques such as China Petrochemical Corp. (1314) and the Australian minerals supplier BHP Billiton Ltd. are prime candidates as they have deeper pockets than many competitors in North America...

Asian bids for BP wells that extend miles beneath the sea surface could preempt the handful of U.S. and European explorers that have dominated Gulf drilling for almost a century. In similar fields, U.S. prospectors McMoran Exploration Corp. and ATP Oil & Gas Corp. are coping with exploding costs and mounting geological challenges, like violent natural gas surges and drill bits melting as they plunge miles into the ocean floor.

“The Gulf of Mexico ticks a lot of boxes for oil companies” from Asia... “The size of the resource is certainly an attraction as well,”

The U.S. section of the Gulf, while producing 17.8 billion barrels of crude in the past six decades, is a more difficult and expensive place to search for oil as explorers push farther off the coast and into more hostile geological formations.

ATP Bankruptcy
Spiraling costs pushed ATP into filing for bankruptcy protection last week. The Houston-based company was one of the first explorers to resume drilling in deep waters of the Gulf after London-based BP’s Macondo oil spill, which was caused by an uncontrolled burst of natural gas.

McMoran spent $906 million in the past three years on a field called Davy Jones that has yet to produce commercial quantities of oil.

Even so, Gulf oil production is expected to jump 31 percent by the end of the decade to 1.83 million barrels a day, the U.S. Energy Department said in a June report.

That’s three times the rate at which Africa and Russia are expected to raise oil production during the same period, and more than twice the forecast increase from Saudi Arabia, according to the U.S. Energy Department. It forecast U.S. Gulf crude prices to climb 34 percent by the end of 2020.

Lv Dapeng, a spokesman in Beijing for China Petrochemical, also known as Sinopec Group, did not answer two calls to his office line seeking comment yesterday. The company had the equivalent of $6.68 billion in free cash flow at the end of 2010, the most recent year reported, according to data compiled by Bloomberg.

‘Limited Pool’
Kelly Quirke, a Melbourne-based spokeswoman for BHP, declined to comment.

“The potential buyers have to have the technical knowledge needed to operate in deep water, and there’s only a limited pool of such companies... It boils down to who has the expertise and who has the deep pockets.”

One attraction of Gulf assets for Chinese companies is the transparency of U.S. regulations and taxation relative to other nations, Loh said. “If you want to drill and develop an oil field it’s easier than, say, in Africa,” he said.

Cnooc Ltd. (883), the publicly traded unit of China’s offshore oil explorer, is poised to become the first Chinese operator of deep-water U.S. oil assets, pending government approval of its $15.1 billion takeover of Canada’s Nexen Inc. Cnooc has pledged to retain Calgary-based Nexen’s drilling experts as part of the transaction announced on July 23.

Track Record
“Chinese oil companies do not have a good track record in developing deep-water projects themselves,” Gordon Kwan of Mirae Asset Securities, said in an interview. “That’s the reason why Cnooc promised to retain all of Nexen’s operational staff in the Gulf of Mexico and not try to send Chinese engineers over.”

BP said it May it plans to divest Gulf fields including Horn Mountain and its minority stake in Ram Powell, about two years after a blowout at its Macondo well in the Gulf killed 11 workers and triggered the worst-ever U.S. marine oil spill. The company expects maximum proceeds of $5 billion to $6 billion after taxes payable by the purchaser, a person familiar with the sale process said last week.

The fields hold proven reserves of about 120 million barrels of oil and produced about 58,000 barrels a day in the first quarter, the person said. In addition to Sinopec Group and BHP, other potential suitors include Woodside Petroleum Ltd., Australia’s second-largest oil company, and China National Petroleum Corp. or its unit PetroChina Co. (857), analysts said.

U.S. Clearance
Chinese companies may wait to pursue deals in the Gulf until Cnooc’s Nexen purchase clears regulatory hurdles, including the Committee on Foreign Investment in the United States, Kwan said. U.S. political resistance in 2005 prompted Cnooc to abandon a bid for California-based Unocal Corp., now part of Chevron Corp.

“If the Cnooc-Nexen deal could be cleared, there should be no problem for Chinese companies bidding for BP assets,” Kwan said. Because any deals with BP would involve individual assets rather than an entire corporation, “I don’t think this would be subject to the same level of vigilance Cnooc-Nexen deal would get from the U.S.”

BHP, Australia’s largest oil and natural-gas producer, already operates the Shenzi and Neptune fields about 120 miles (193 kilometers) off the Louisiana coast. The company also is a partner with BP in the nearby Mad Dog and Atlantis projects.

The BP fields for sale “are attractive tier-one assets that fit within BHP’s strategy that rarely come up for sale,” said Fagan, the JPMorgan analyst.

Worth Looking
Woodside began exploring in the Gulf of Mexico in 1999 and has 20 percent stakes in the Neptune and Power Play oilfields, according to the company’s website...

...Woodside, operator of the A$15 billion Pluto natural-gas project in Western Australia, said in February it’s considering expansion outside the country through new partnerships...

One person familiar BP’s plans said bidders may include U.S. companies such as Chevron Corp. and Exxon Mobil Corp., and that it’s unlikely that all the fields will go to one buyer.

‘Rock Star’
Other U.S. producers tested by the vagaries of Gulf drilling have included McMoran and Cobalt International Energy Inc. Despite the setbacks at the Davy Jones project, McMoran Chairman and Co-Founder James “Jim Bob” Moffett retains “rock star” status within the oil industry, Brookshire’s Bern said.

On the sidelines of a Denver energy conference last week, Moffett’s informal question-and-answer session with investors and geologists drew a standing-room only crowd.

Cobalt, controlled by Goldman Sachs Group Inc. and Riverstone Holdings, lost $99 million on its Ligurian field in the Gulf during the second quarter. The Houston-based company, which also explores off the coasts of Angola and Gabon, plans to continue deep-water Gulf exploration with its North Platte 1 well and the Anadarko Petroleum Corp.-operated Shenandoah field, according to a July 31 company statement.



http://www.bloomberg.com/news/2012-...l-drillers-in-u-s-gulf-seen-with-bp-sale.html
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http://www.bloomberg.com/news/2012-...-billion-barrels-in-perdido-oil-deposits.html



Pemex May Have 10 Billion Barrels in Perdido Oil Deposits
By Carlos Manuel Rodriguez and Nacha Cattan
August 29, 2012

Petroleos Mexicanos, the world’s fourth-largest oil producer, may have as many as 10 billion barrels of potential reserves in its El Perdido deposits in the Gulf of Mexico, a company executive said.

The Trion-1 exploration well in El Perdido, where the company struck its first deep-water oil, may hold 250 million to 500 million barrels, Deputy Exploration Director Jose Antonio Escalera said in an interview in Mexico City after the discovery’s announcement today. Mexican President Felipe Calderon said earlier that Trion may hold more than 400 million barrels of light oil.

Pemex, as the state-owned company in known, is counting on deep-water Gulf of Mexico deposits to increase production by a third in the next dozen years. The company estimates it has 27 billion barrels of untapped crude in the Gulf.

“This is a great discovery,” Calderon said. “It further strengthens our hydrocarbon reserves and allows Mexico to maintain and increase oil production in the medium and long term.”

Trion is 8,333 feet (2,540 meters) deep and located 39 kilometers (24 miles) from the maritime border with the U.S. If the 10 billion barrels prove to be recoverable, the Perdido area would be the biggest discovery by Pemex since Cantarell, the world’s third-largest field when it was found in 1976.

No Crude
Pemex found no commercially viable deep-water crude in its first 22 attempts. The Mexico City-based company allocated 15 billion pesos ($1.1 billion) for this year’s deep-water projects.

Pemex expects to start producing sweet light oil from Trion in as soon as five years, Carlos Morales, Pemex’s head of exploration and production, said. Pemex invested $120 million in the Trion project, he said.

The company will get results in a month from another ultra- deep-water exploratory well called Supremus-1, which is 9,514 feet deep, Morales said. Supremus is also being drilled in the Perdido Fold Belt.

“This is one of the most important oil discoveries in deep waters” anywhere, Morales said.

Oil producers such as Royal Dutch Shell Plc, BP Plc and Chevron Corp. are already pumping crude from the U.S. side of the Perdido region, where the companies operate the world’s deepest spar production facility.

On Feb. 20, Mexico and the U.S. established a legal framework that created incentives for U.S. energy companies to develop oil and gas resources jointly with Pemex.

The accord helps to resolve issues such as whether oil extracted from the Mexican side of the Gulf but sent directly to crude terminals in the U.S. is considered Pemex output and imported crude, and whether Mexico will charge royalties on it.



http://www.bloomberg.com/news/2012-...-billion-barrels-in-perdido-oil-deposits.html
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http://bishophill.squarespace.com/blog/2012/8/31/hiway-to-heaven.html



Hiway to heaven
August 31, 2012
by "Bishop Hill" (Andrew W. Montford)

The advent of horizontal drilling has famously combined with the older hydraulic fracking technique to bring about a revolution in the global energy industry (outside the EU that is, for within the Union poverty generation dominates the political agenda). So while European consumers worry about their energy bills, in North America, the glut of shale gas has caused a collapse in gas prices, to the extent that few in the gas industry can now make money.

However, with the technology being so new, innovation is still an important factor in the economics of shale gas and it is therefore not unexpected that cost is being driven out of the system.




Schlumberger's clever frack takes aim at gas costs
Fri, Aug 31 07:30 AM EDT
By Andrew Callus

STAVANGER, Norway (Reuters) - Production costs of natural gas from unconventional fields could tumble in the United States if a new technique developed by Schlumberger lives up to its billing.

The world's largest oilfield services company by market value and others working in the industry have suffered this year because the runaway success of hydraulic fracturing (fracking) and horizontal drilling techniques to extract so-called unconventional gas has created a glut and caused a price slide.

But using a proprietary system called Hiway that only became commercially viable last year, Schlumberger's fracker in chief believes he has knocked a lump out of the infant industry's three major cost components; water, sand, and trucks.

Schlumberger is already using the system on nearly a third of all fracking jobs, and expects that to rise rapidly to 50-70 percent, according to Kyel Hodenfield, the company's vice president for unconventional resources.

"It can vary, but using Hiway we generally say you need 40 percent less proppant," (graded sand mixed with guar gum or lubricating chemicals), he told Reuters in an interview.

"Water is more variable, but it's somewhere between 20 and 50 percent less."

Less sand, less water and less pumping adds up to fewer trucks, Hodenfield explained on the sidelines of the Offshore Northern Seas (ONS) conference in Stavanger, Norway.

"Those are the big costs. Anything you can do to reduce the amount of sand, the amount of water, and the amount of horsepower is going to fall to the bottom line."

Fracking, often combined with modern horizontal drilling techniques, recovers previously unreachable gas by fracturing the rock that contains it and then pumping in fluid and mined or manufactured sand to hold open the cracks and force out the gas.

The process, pioneered in the United States, requires many more wells to be drilled than traditional oil and gas extraction. The fracking generally takes just a few days, even though some fracked fields will produce for years, so the infrastructure, materials and equipment need to be mobile.

At some sites, water is piped in, but usually, both sand and water are trucked to the site. More trucks are needed to provide the horsepower to pump the mixture into the cracks, and road regulations restrict their size, so the number of heavy vehicles per site can be considerable.

Schlumberger is the number-two in fracking services, as measured by the horsepower of its fleet, with a 12 percent share of the market in 2011, according to analysts at Global Hunter Securities.

It lies behind Halliburton and ahead of Baker Hughes in the ranking, although its exposure to the industry is relatively small in the context of its traditional oil and gas services business worldwide. Hodenfield would not reveal how much of Schlumberger's business is now in U.S. unconventionals, "but I can say it's grown, a lot", he said.

FIBRE INJECTION
So how does Hiway work?

Hodenfield, who grew up in North Dakota where the Bakken field is at the centre of the U.S. shale gas boom, brightens at the opportunity to explain a process that adds a proprietary fiber to the traditional sand and fluid mix, and uses a "pulsing" system to send globs of the fiber in between each injection.

The dissolvable fiber globs create more effective channels for the gas to flow, and the pulsing rhythm can be made to match the geological structure of the rock, also pushing the sand deeper into the cracks and resulting in more effective openings that conduct gas better for every liter pumped in.

Hiway is not the only new technique on the scene as oil companies look to use fracking to reach more lucrative oil as well as gas.

Schlumberger and other innovators are also using sophisticated seismic techniques, combined with data from pilot wells, to reduce the number of fracks along a drill pipe and target only the "sweet spots" in the field.

Together, these new techniques and smart rugged sensor kit from National Instruments can also reduce the production pace variability that plagues the unconventional industry.

And according to one senior executive at one of the world's major oil companies, these cost-saving innovations may only be the beginning.

"It's mostly brute force up to now," he said. "When the oil majors get serious about investment in fracking the cost could fall by half."

U.S. fracking expenditure is not pocket change. Hodenfield cites data from analysts Spears & Associates saying the total onshore oil and gas industry drilling and completions spend, boosted mainly by unconventional work, has soared to $150 billion a year from $20 billion in 2002.

This eclipses the offshore spend, which was at a similar $20 billion level 10 years ago and has only recently recovered to that level after the Macondo oil spill disaster of 2010.

Hodenfield says smarter technology is also the key to reducing the environmental impact of fracking in shale rock, tight gas, coal bed methane and other unconventional gas fields.

"We have a choice," he said. "We can take the brute force approach and drill a lot of wells and frack a lot of wells and live with the production variation and compensate that by drilling even more wells (with the consequent environmental footprint), or you drill only the best wells by defining the sweet spot and optimize the completion by technology."



http://mobile.reuters.com/article/idUSBRE87U0GE20120831?irpc=932
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thør said:
They might need some of that to repair the foundation of that pretty building in 10 years or so.
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Eh? We can't have that. I need that money.

What gives? Bad foundation engineering design? Poor construction? Permafrost melt?



 
trysail said:

Eh? We can't have that. I need that money.

What gives? Bad foundation engineering design? Poor construction? Permafrost melt?
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Let's just say that the Russians have different standards than we do as far as how their buildings should perform.
 
http://www.bloomberg.com/news/2012-...s-for-drilling-oil-without-humans-energy.html



NASA Helps Hatch Robots for Drilling Oil Without Humans
By David Wethe
September 2, 2012

NASA’s Mars rover has something to teach the oil industry.

Traversing the Red Planet while beaming data through space has a lot in common with exploring the deepest recesses of earth in search of crude oil and natural gas. Robotic Drilling Systems AS, a Norwegian company developing a drilling rig that can think for itself, signed an information-sharing agreement with NASA to discover what it might learn from the rover Curiosity.

The company’s work is part of a larger futuristic vision for the energy industry. Engineers foresee a day when fully automated rigs roll onto a job site using satellite coordinates, erect 14-story-tall steel reinforcements on their own, drill a well, then pack up and move to the next site.

“You’re seeing a new track in the industry emerging,” says Eric van Oort, a former Royal Dutch Shell Plc executive who’s leading a new graduate-level engineering program focused on automated drilling at the University of Texas at Austin. “This is going to blossom.”

Apache Corp., National Oilwell Varco Inc., and Statoil ASA are among the companies working on technology that will take humans out of the most repetitive, dangerous, and time-consuming parts of oil field work.

“It sounds futuristic,” says Kenneth Sondervik, sales and marketing vice president for Robotic Drilling Systems. He compares it to other areas that have become highly automated, such as car manufacturing or cruise missile systems.

Tough Sell
Until recently, robots have been a hard sell in an industry that has long relied on human ingenuity, says Mark Reese, president of rig solutions at National Oilwell Varco.

“In the past, it’s been all about, ‘We need more and more people and experience, and that’s the only way to accomplish this task,’” Reese said.

The 2010 BP disaster in the Gulf of Mexico helped shift attitudes, says Clay Williams, chief financial officer at National Oilwell Varco. Eleven men were killed when the Deepwater Horizon rig caught fire and sank. Statoil has projected that automation may cut in half the number of workers needed on an offshore rig and help complete jobs 25 percent faster, says Steinar Strom, former head of a research and development unit on automation at the Norwegian company.

Robot Deckhands
Robotic Drilling Systems is designing a series of robots to take over the repeatable tasks now done by deckhands, roughnecks, and pipehandlers on a rig. Its blue, 10-foot-tall robot deckhand has a jointed arm that can extend about 10 feet, with 15 or so interchangeable hands of assorted sizes. The robot is anchored in place to give it better leverage as it lifts drill bits that weigh more than a ton and maneuvers them into place.

The company also is collaborating with researchers at Stanford University on a three-fingered robot hand embedded with sensors that give it a touch delicate enough to pick up an egg without crushing it.

The Mars rover is designed to collect data and take action on its own based on programmed reasoning. As a step in that direction, some companies are working on technology that will make drill bits more intelligent and able to respond instantly to conditions they encounter, such as extreme temperatures or high pressures.

National Oilwell Varco, the largest U.S. maker of oilfield equipment, and Schlumberger Ltd., the world’s largest oilfield services provider, have developed drill pipe wired with high- speed data lines to allow the bit to feed information to workers at the surface.

Thinking Bits
Apache, the third-largest U.S. independent oil and natural- gas producer by market value, is writing software that will essentially allow the drill bit to think for itself, communicating directly with equipment at the surface that controls speed and direction.

Graham Brander, the company’s director of worldwide drilling, sees it working much like a plane on autopilot, flying on its own with a human on standby, ready to assume the controls if necessary.

“That’s what I view very much as the automation model for the oil and gas business,” he says.

Other breakthroughs are taking place onshore, where producers are racing to drill tens of thousands of wells in U.S. shale fields. On a recent morning in north Houston, Johnny Alverson, a senior foreman at rig builder Drilling Structures International Inc., fired up an 1,800-horsepower John Deere engine and picked up a remote control box as big as a car battery as he prepared to move a 167-foot-tall drilling rig without the aid of a crane.

With the push of a couple of buttons on the remote, the green light lit up next to “walk” and the rig slowly heaved itself up five inches off the ground on four large, flat feet. The $20 million monster can move at a rate of a foot a minute. Says Drilling Structures Executive Vice President P.J. Rivera: “You start to feel good about yourself when you can pick up a million pounds with the flick of a thumb.”



http://www.bloomberg.com/news/2012-...s-for-drilling-oil-without-humans-energy.html
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http://www.sciencedaily.com/releases/2000/01/000127082228.htm


Scientists Find That Tons Of Oil Seep Into The Gulf Of Mexico Each Year

ScienceDaily (Jan. 27, 2000) — Twice an Exxon Valdez spill worth of oil seeps into the Gulf of Mexico every year, according to a new study that will be presented January 27 at the Ocean Sciences Meeting in San Antonio, Texas.

But the oil isn't destroying habitats or wiping out ocean life. The ooze is a natural phenomena that's been going on for many thousands of years, according to Roger Mitchell, Vice President of Program Development at the Earth Satellite Corporation (EarthSat) in Rockville Md. "The wildlife have adapted and evolved and have no problem dealing with the oil," he said.

Oil that finds its way to the surface from natural seeps gets broken down by bacteria and ends up as carbon dioxide, a greenhouse gas. So knowing the amount of fossil fuel that turns to carbon dioxide naturally is important for understanding how much humans may be changing the climate by burning oil and gas.

Using a technique they developed in the early 1990s to help explore for oil in the deep ocean, Earth Satellite Corporation scientists found that there are over 600 different areas where oil oozes from rocks underlying the Gulf of Mexico. The oil bubbles up from a cracks in ocean bottom sediments and spreads out with the wind to an to an area covering about 4 square miles.

"On water, oil has this wonderful property of spreading out really thin," said Mitchell. "A gallon of oil can spread over a square mile very quickly." So what ends up on the surface is an incredibly thin slick, impossible to see with the human eye and harmless to marine animals.

When oil spreads out over water, surface tension causes it to act like a super-thin sheet of Saran Wrap, flattening down small waves on the ocean surface. To spot the oil slicks, EarthSat scientists use radar data from Canadian and European satellites. The oil slicks stand out in the radar image because they return less of the radar signal than the wavy surfaces.

To get an estimate of how much oil seeps into the Gulf each year, the researchers took into account the thickness of the oil-only a hundredth of a millimeter, the area of ocean surface covered by slicks, and how long the oil remains on the surface before it's consumed by bacteria or churned up by waves. "The number is twice the Exxon Valdez's spill per year, and that's a conservative estimate," said Mitchell.

With funding from NASA, EarthSat researchers began this work in the early 1990s using Landsat satellite and radar data to identify marine oil seeps for petroleum exploration. The method has had amazing success. Drilling for oil in the ocean is extremely expensive, and with radar data, oil companies have a much better shot at finding oil deposits.

In the future, EarthSat hopes to refine this method using data from NASA's new EO-1 satellite, set for launch in June 2000. A sensor aboard EO-1 may be able to tell gas from oil and better pinpoint the source of the slick.


http://www.sciencedaily.com/releases/2000/01/000127082228.htm
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http://oils.gpa.unep.org/facts/natural-sources.htm


Natural sources of marine oil pollution

Crude oil and natural gas seeps naturally out of fissures in the ocean seabed and eroding sedimentary rock. These seeps are natural springs where liquid and gaseous hydrocarbons leak out of the ground (like springs that ooze oil and gas instead of water). Whereas freshwater springs are fed by underground pools of water, oil and gas seeps are fed by natural underground accumulations of oil and natural gas (see USGS illustration: http://oils.gpa.unep.org/facts/natural-sources.htm#USGS ). Natural oil seeps are used in identifying potential petroleum reserves.

As pointed out by the National Research Council (NRC) of the U.S. National Academy of Sciences, "natural oil seeps contribute the highest amount of oil to the marine environment, accounting for 46 per cent of the annual load to the world's oceans. -- Although they are entirely natural, these seeps significantly alter the nature of nearby marine environments. For this reason, they serve as natural laboratories where researchers can learn how marine organisms adapt over generations of chemical exposure. Seeps illustrate how dramatically animal and plant population levels can change with exposure to ocean petroleum".

NOAA ( http://oils.gpa.unep.org/facts/natural-sources.htm#NOAA ) describe a natural seepage area in California: "One of the best-known areas where this happens is Coal Oil Point along the California Coast near Santa Barbara. An estimated 2,000 to 3,000 gallons of crude oil is released naturally from the ocean bottom every day just a few miles offshore from this beach".


U.S. Geological Survey (USGS): Basics about oil and gas seeps • Seeps and the environment • Natural oil and gas seeps in California.

U.S. Minerals Management Service (MMS): Natural oil and gas seepage in the coastal areas of California.

Sciency Daily: "Scientists find that tons of oil seep into the Gulf of Mexico each year". Article published in 2000.

U.S. National Academy of Sciences: Oil in the sea III: Inputs, fates and effects. Report 2002 by the National Research Council (NRC) Committee on Oil in the Sea: Inputs, Fates, and Effects. See also U.S. National Academies press release about the conclusions in the NRC Report, and Web Extra on Oil (including summary of sources of oil). See also references to the figures published in the 1985 NRC report: on the Ocean Planet Exhibition web site, and on the web page Oil in the sea: About offshore oil and gas. (U.S.) National Ocean Industries Association.

U.S. NOAA: General oil spill questions (FAQs). U.S. National Oceanic and Atmospheric Administration (NOAA) Office of Response and Restoration.
Caspian Environment Programme: Natural oil seeps in the Caspian Sea.

U.S. NASA: Tons of oil seep into the Gulf of Mexico each year. Earth Observatory. U.S. National Aeronautics and Space Administration (NASA).

APPEA: Discovery: Explore the world of oil and gas: Oceans and oil spills. Australian Petroleum Production and Exploration Association (APPEA).

GESAMP: "Impact of oil and related chemicals and wastes on the marine environment". GESAMP Report 50, 1993. Not available online, but the figures referred to can also be found in the online article "Oil pollution of the sea".
UN Atlas of the Ocean: The impact of marine pollution. Report (1980) by Douglas J. Cuisine and John P. Grant. Table published on the UN Atlas of the Oceans web site.



http://oils.gpa.unep.org/facts/natural-sources.htm
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Sonofabitch. It seems that every time these guys drill a well into the presalt they find large quantities of good quality petroleum.



http://www.reuters.com/article/2012...9?feedType=RSS&feedName=rbssEnergyNews&rpc=43

Wed Sep 19, 2012
6:16pm EDT

* Brazilian oil company says crude 28-30 degrees on API

* Franco SW well the latest find in Santos offshore basin

SAO PAULO, Sept 19 (Reuters) - Brazil's state-led oil company Petrobras said on Wednesday that analysis confirmed the presence of "good quality" crude in a deepwater field south of Rio de Janeiro, adding to discoveries in one of the world's most promising offshore oil frontiers.

Petrobras said it had verified a 438-meter (1,437-foot) column of hydrocarbons in a prospect known as "Franco SW" in the Santos offshore basin about 210 kilometers south of Rio de Janeiro, according to a securities filing.

Petrobras said the oil discovered is a relatively light grade of crude, between 28 degrees and 30 degrees on the American Petroleum Institute (API) scale. That's lighter than most of the oil Petrobras produces in Brazil, meaning the crude should be easier and cheaper to refine than current output.

Franco SW was drilled 17 kilometers to the south of the "Franco" prospect, at a depth of 2,024 meters beneath the ocean's surface.

In 2010 Petrobras said an exploratory well at Franco found an estimated 6 billion barrels of oil and natural gas equivalent.



http://www.reuters.com/article/2012...9?feedType=RSS&feedName=rbssEnergyNews&rpc=43
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Cross-posted in "Today in Anchorage" and "That Pipeline" threads.

http://www.bloomberg.com/news/2012-...a-driving-annual-20-billion-via-pipeline.html




Alaska Sees Asia Driving Annual $20 Billion Via Pipeline
By Edward Klump
September 24, 2012

Alaska wants a $50 billion pipeline and export complex built to develop natural gas that’s stranded on its icy North Slope. The justification: Asia’s swelling appetite for the fuel.

Governor Sean Parnell gave Exxon Mobil Corp., BP Plc and ConocoPhillips to the end of this month to provide plans to pipe the gas south and compress it into a liquid, known as LNG, for export. Their joint venture would compete with growing global supplies of LNG coming into markets within two decades from Australia, East Africa, the U.S. Gulf Coast and Canada.

Energy explorers and Alaska’s government are trying for the first time to market a resource that may generate as much as $20 billion in annual gas sales. Asian gas buyers as of July paid almost six times the futures price in the U.S., where it has been driven low by the shale boom.

“It’s gas in search of a market,” Kevin Book, a managing director with Washington-based ClearView Energy Partners, an industry consulting group, said in an interview.

The explosion of output from U.S. shale squelched Alaska’s long-held hopes to build a pipeline to the Lower 48 U.S. states, Book said. “So the next most logical place to take it is to liquefy it and ship it at significant price premiums to Japan, China and throughout the Pacific Rim.”

Gas Imports
Asian demand will lead a 17 percent global increase in gas demand by 2017 from 2011, the International Energy Agency forecast in June. China’s annual gas consumption will more than double to 273 billion cubic meters in the period, the IEA said. Chinese gas consumption in 2017 would equal about 28 percent of the reserves identified on Alaska’s North Slope.

The northernmost U.S. state is counting on oil for more than 90 percent of the $8.44 billion in unrestricted general fund revenue it expects to get in fiscal year 2013. Alaska may have to consider gas imports to supply its population centers in future years.

An 800-mile pipeline project from northern Alaska to a southern port may cost $20 billion to $26 billion -- or about three times as much as TransCanada Corp.’s Keystone pipeline proposal to link Canada’s oil sands to the U.S. Gulf Coast, according to a 2010 estimate of the Alaska project.

Industry estimates have pegged Alaska’s LNG total project cost at $40 billion to $50 billion, factoring in a pipeline and liquefaction plant. A Kitimat LNG project on Canada’s western coast may cost about $15 billion, including a plant, pipeline and wells, according to an estimate from Apache Corp., which is working on the proposal with Encana Corp. and EOG Resources Inc.

Export History
Alaska, the only U.S. state operating an LNG export plant, is seeking to parlay its more than 40-year history of sending fuel to Asia from ConocoPhillips’s terminal near Kenai into an advantage for expanding shipments.

The state’s coast provides one of the closest routes to Asian markets, potentially giving it lower shipping costs than competing projects from western Canada, Robert Brooks, founder of RBAC Inc., an energy data company, said in an interview.

Alaska’s isolated location may help insulate it from discussions about whether the U.S. should be exporting gas pumped domestically, Larry Persily, federal coordinator for Alaska gas-transportation projects, said in a phone interview.

“Sending Alaska gas overseas would not deprive petrochemical companies or utilities in Milwaukee or Shreveport of gas,” he said. “I think generally Alaska gas is absent from those political debates.”

Asian Consumption
By 2025, the four largest consumers of LNG will be Japan, China, India and South Korea, according to a presentation by BG Group Plc. In 2011, the top four countries were Japan, South Korea, U.K. and Spain, BG said. U.S. LNG imported by Japan fetched $17.58 per million British thermal units in a period ending in July, according to LNG Japan Corp. U.S. gas futures averaged $2.963 per million Btus during the same month in New York.

At the same time, North American LNG developers are seeking to escape a low-price U.S. gas market, where shale formations flooded the market with supplies. Gas futures touched a 10-year low in April of less than $2 per million British thermal units.

Exxon, ConocoPhillips and BP, three of Alaska’s biggest oil and gas producers, laid out plans to consider Alaska LNG in a March 30 letter to Governor Parnell. The North Slope holds more than 35 trillion cubic feet of discovered gas, the companies said. That’s nearly four times the U.K.’s estimated 9 trillion cubic feet of proved gas reserves, according to the U.S. Energy Information Administration.

‘Unprecedented’ Capital
Unlocking the fuel through “unprecedented” capital commitments for gas would require “competitive and stable fiscal terms,” Exxon, ConocoPhillips and BP said in the March letter. Exxon has outperformed its peers this year, gaining 8.5 percent in the period, while the Dow Jones Oil & Gas Titans 30 Index climbed 4.1 percent. ConocoPhillips rose 3.3 percent, and BP lost 3.9 percent, in the year through Sept. 24.

The existing ConocoPhillips plant near Kenai is small by today’s global standards, capable of processing 240 million cubic feet of gas a day. Its exports diminished in recent years as nearby gas fields played out, leaving the terminal’s future in question.

A new LNG site may have a capacity of about 3 billion cubic feet a day, said Kurt Gibson, director of the Alaska Gas Pipeline Project Office. That would generate about $20 billion in annual sales, based on prices Japan paid for LNG as of July.

Exxon, BP and ConocoPhillips have said their assessment will include potential pipeline capacities and routes, as well as LNG terminal sites. Proposals may look at expanding the Kenai facility or building a new terminal farther east at Valdez, which already has a port used by large oil tankers.

‘Early Days’
It remains “early days” for a project, Tony Palmer, a vice president for TransCanada, which is working with the producers on an export plan, said in a telephone interview.

“Advancing a project of this scale and complexity is extremely risky for the sponsors,” Palmer said. “It’s a lengthy process. It’s a costly process.”

TransCanada continues to evaluate the LNG project with producers, Palmer said. Exxon, ConocoPhillips and BP also said they are continuing the examination.

Reviewing global trends in LNG will be part of the assessment of a possible gas project, the companies told Parnell. The soonest a new export project would begin is probably post-2020, Asish Mohanty, a senior analyst of global LNG at Wood Mackenzie in Houston, said in an interview.

Persily, the federal coordinator for Alaska gas- transportation projects, has been watching the state’s efforts to export gas since 1976 and has seen those plans repeatedly frustrated.

“By the time Alaska gas could get there 10 years from now, would there still be that attractive market, or are we always coming up short, as we have for 40 years?”



http://www.bloomberg.com/news/2012-...a-driving-annual-20-billion-via-pipeline.html
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