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Insight: Natural gas pain is oil’s gain as frack crews head to North Dakota

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By Selam Gebrekidan
NEW YORK | Mon Mar 19, 2012 4:43am EDT

(Reuters) – Collapsing natural gas prices have yielded an unexpected boon for North Dakota‘s shale oil bonanza, easing a shortage of fracking crews that had tempered the biggest U.S. oil boom in a generation.

Energy companies in the Bakken shale patch have boosted activity recently thanks to an exceptionally mild winter and an influx of oil workers trained in the specialized tasks required to prepare wells for production, principally the controversial technique of hydraulic fracturing.

State data released this month showed energy companies in January fracked more wells than they drilled for the first time in five months, suggesting oil output could grow even faster than last year’s 35 percent surge as a year-long shortage of workers and equipment finally begins to subside.

As output accelerates, North Dakota should overtake Alaska as the second-largest U.S. producer within months, extending an unexpected oil rush that has already upended the global crude market, clipped U.S. oil imports, and made the state’s economy the fastest-growing in the union.

Six new crews trained in “well completion” — fracking and other work that follows drilling — have moved into North Dakota in the past two months alone, according to the state regulator and industry sources. Back in December, the state was 10 crews short of the number needed to keep up with newly drilled wells.

“Three to four months ago, the operators were begging for fracking crews,” said Monte Besler, who consults companies on fracking jobs in North Dakota’s Bakken shale prospect. Now “companies are calling, asking if we have a well to frack.”

For the last three years, smaller oil companies with thin pockets were forced to wait for two to three months before they could book fracking crews and get oil out of their wells. As more and more wells were drilled, that backlog has grown.

Last year, an average 12 percent of all oil wells were idled in North Dakota. Even so, output in January hit 546,000 barrels per day, doubling in the last two years and pushing the state ahead of California as the country’s third-largest producer.

FEWER WELLS IDLE

Fracking, which unlocks trapped oil by injecting tight shale seams with a slurry of water, sand and chemicals, has drawn fierce protests in some parts of the country, but it has not generated heated opposition in North Dakota.

The number of idle wells waiting to be completed in the state reached a record 908 last June, the result of a new drilling rush and heavy spring floods. Only 733 wells were idle in August as crews caught up, but the figure crept steadily higher until the start of this year.

Now, the industry may be turning a corner in North Dakota, the fastest-growing oil frontier in the world.

“Both rig count and hydraulic fracturing crews are limiting factors. Should they continue to rise together, production will not only increase, it will accelerate,” said Lynn Helms, director of the state Industrial Commission’s Oil and Gas Division.

The tame winter likely played an important role in helping reduce the number of idle wells — those that have been drilled but not yet fracked and prepped for production. That number fell by 11 in January, as oil operations that would normally be slowed by blizzards were able to carry on, experts said.

Residents of the northern Midwest state — accustomed to temperatures as low as minus 40 degrees Fahrenheit (-40 Celsius) in winter and snow piles as high as 107 inches — this year enjoyed the fourth warmest since 1894, according to the National Weather Service.

The milder conditions also helped prevent the usual exodus of warm-weather workers that occurs when blizzards set in.

“Not everyone wants to work in North Dakota in the winter,” Besler said.

The backlog of unfinished wells has also begun to subside because the pace with which new wells are drilled has leveled off. The state hasn’t added new rigs since November.

The latest state data shows oil companies brought 37 new rigs to North Dakota’s in 2011 but have not added more since November. The rig count held steady at 200 in January 2012, although more than 200 new wells were drilled in that period.

SLUMPING NATGAS PRICE PROVIDES RELIEF

North Dakota has gotten a boost from the fall-off in natural gas drilling due to the collapse in prices to 10-year lows. Energy companies such as Chesapeake and Encana have shut existing natural gas wells and cut back on new ones. Last week, the number of rigs drilling for gas in the United States sank to the lowest level in 10 years as major producers slimmed down their gas business, according to data from Houston-based oil services firm Baker Hughes. [ID:nL2E8EG9OY] The fewer gas wells drilled, the less need for skilled fracking crews in the country’s shale gas outposts.

Fracking in oil patches is similar to the process used in gas wells, except for the inherent power of the pumps employed. Crews inject high-pressure water, sand and chemicals to free hydrocarbons trapped in shale rock. So big service firms such as Halliburton, Baker Hughes and Schlumberger  are reshuffling crews from shale gas fields to oil prospects in the badlands. “We have moved or are moving about eight crews. Some of those crews are moving as we speak,” Mark McCollum, Halliburton’s chief financial officer, said at an industry summit in February.

Halliburton declined to specify where the crews were moving.

Calgary-based Calfrac moved one crew into the Bakken in late 2011, according to an SEC filing. Privately owned FTS International no longer works in the gas-rich Barnett shale but has set up operations in the Utica, an emerging prospect in Ohio and western Pennsylvania, according to a company representative.

The reallocations come with some efficiency losses. Halliburton had to scale back its 24-hour operations and is still trying to solve logistical problems. “You actually take the crew from one basin and they have to go stay in motels, you have to pay them per diems for a while. And then you have to double up your personnel while you’re training new, locally based crew on the equipment once it is moved,” McCollum said.

At the same time, a shortage of key equipment such as pressure pumps is easing as companies start taking delivery of material ordered months or even years ago.

It takes about 15 such pumps to frack a gas well, and many more for oil wells. The total pressure-pumping capacity in the United States at the end of 2012 will be 19 million horsepower, two-and-a-half times more than in 2009, according to Dan Pickering, analyst with Tudor Holt and Pickering in Houston.

FRACKING AROUND THE NATION

Easing personnel constraints suggest recruiters may be meeting with success in nationwide campaigns to attract workers with specialized knowledge of complex pumps and hazmat trucks — and a willingness to brave harsh conditions.

Even with U.S. unemployment at 8.3 percent, such skilled labor remains in short supply despite salaries from $70,000 to $120,000 a year. In North Dakota, unemployment was just 3.2 percent in January, the lowest rate in the nation.

Fracking crews, much like roughnecks on drilling rigs, clock in 12-hour shifts for two straight weeks before getting a day off. They live in camps far from cities and towns. Jobs are transient — a few weeks at a single location. Most workers divide their time between the California desert, Texas ranchlands and the freezing badlands of the Midwest state.

Companies have scrambled to nab talent, with recruiters scouring far and wide. Military bases have gotten frequent visits, and some companies have hired truckers from Europe.

“There’s definitely a push to look all over for people who have good experience since it takes at least six months to train someone how to use a fracking pump,” said David Vaucher, analyst with IHS Cambridge Energy Research.

(Editing by David Gregorio)

Analysis: Tapping oil from reserve may be trickier than ever

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By Ayesha Rascoe
WASHINGTON | Fri Mar 16, 2012 1:01pm EDT

(Reuters) – The U.S. Strategic Petroleum Reserve is not quite as strategic as it used to be.

As President Barack Obama moves closer to an unprecedented second release of the U.S. emergency oil stockpile in a bid to bring down near-record fuel prices, experts say dramatic logistical upheavals in the U.S. oil market over the past year may now make such a move slower and more complicated.

Moving to tap the four giant Gulf Coast salt caverns that hold 700 million barrels of government-owned crude would still almost certainly knock global oil futures lower, delivering some relief at the pump for motorists and helping Obama in the November election if he can prevent gasoline from rising above $4 a gallon nationwide.

On Thursday, prices fell by as much as $3 a barrel after Reuters reported that Britain was set to agree to release stockpiles together with the United States later this year. UK officials said the timing and details of the release would be worked out prior to the summer, when prices often peak.

But the logistics of getting that crude oil to willing refiners are more complicated than ever.

The reversal of a major Texas-to-Oklahoma pipeline will lower the distribution capacity of the SPR’s largest cavern, according to John Shages, who oversaw the U.S. oil reserves during the Bush and Clinton administrations. A resurgence in domestic oil output and the potential closure of the East Coast’s biggest refinery is curtailing demand for crude.

There is little doubt that SPR oil would eventually find buyers, since it is basically auctioned to the higher bidder. But it may move more slowly than the government hopes.

“The logistical system in the United States is shifting,” said Guy Caruso, the former head of the Energy Information Administration. “That probably is going to cause SPR officials to rethink how that oil would be distributed especially in an extreme scenario.”

The mechanics of the release may prove almost as tricky for Obama as rallying international support for a second intervention in as many years, or fending off attacks from Republicans who will likely brand it as a pre-election gimmick.

ANOTHER ERA

The U.S. shale oil boom and rising imports of Canadian oil sands crude have transformed the U.S. energy landscape, with industry now scrambling to move a glut of oil from the center of the country down to the U.S. Gulf Coast — reversing historical trends that were the basis for the SPR’s original planning.

The nation’s emergency oil stockpile, created by Congress in the mid-1970s after the Arab oil embargo, was designed to transport oil primarily via pipeline from the Gulf to refineries in the area and to buyers further north.

“The fact that pipelines go south and not north is a major change,” says Edward Morse, global head of commodities research at Citigroup and a former energy expert at the State Department.

The Department of Energy says the SPR can distribute crude to 49 refineries with a capacity of more than 5 million barrels per day — about one-third the U.S. total — and five marine terminals. It is designed to be capable of releasing oil within two weeks of an order, and to sustain a rate of 1 million bpd for as long as a year and a half, enough to meet 5 percent of U.S. demand.

Today it can discharge oil at a maximum rate of 4.25 million bpd, just below its 4.4 million bpd design capacity, a department official said. The reduction was due to a damaged storage tank.

Industry analysts, however, are skeptical.

Morse says that the maximum rate now appears unachievable, and that logistical problems constrained the government’s release of 30 million barrels of oil last summer — its largest ever — in response to the disruption of Libyan oil supplies.

Oil from the reserves must compete with crude already being transported via pipeline or tanker, often on crowded waterways, so there may not be enough capacity in the system to immediately take in millions of additional barrels of oil.

The Energy Department released an average of 743,000 bpd last August.

The department said it conducts thorough assessments of commercial capabilities to move oil from the reserves on a routine basis and remains confident it could supply the market with 4.25 million bpd if needed.

Many analysts doubt that much would ever be needed at once.

“Absent a serious disruption of great magnitude, it is inconceivable that the U.S. would draw down its inventory of SPR at the maximum rate,” said Shages, who now runs his own firm, called Strategic Petroleum Consulting, LLC.

SEAWAY, PHILADELPHIA

Even so, the system now has less flexibility.

The move to reverse the flow of the 350,000 bpd Seaway Pipeline to move crude oil from Cushing, Oklahoma, where there is a glut, to Gulf Coast refineries will almost certainly hurt the distribution capability of the SPR’s Bryan Mound storage tank in Freeport, Texas, says Shages.

Bryan Mound is the largest of the four sites, capable of holding about a third of the SPR’s total crude. About 43 percent of last year’s release came from Bryan Mound, data show.

After operator Enterprise Products completes the process of reversing the line by June, it will be limited to shipping crude via two Gulf of Mexico terminals and a system of local pipelines into Houston area refineries.

But Bryan Mound will still be able to discharge crude at a rate of 1.25 million bpd, according to an energy department official.

“When the pipeline is reversed, the distribution capability of crude from the SPR site will still be nearly 25 percent more than the site’s maximum drawdown rate, ensuring more than sufficient distribution capability,” the official said.

The Capline from Louisiana to Illinois, the largest such south-to-north pipeline, in theory has plenty of spare capacity since it has been running at less than a quarter of its 1.2 million bpd — but that is because a glut of Canadian and North Dakota crude is already sating the big Midwest refiners.

Meanwhile Gulf Coast plants are filling up on growing output from the Eagle Ford shale in Texas, reducing import demand. Because most U.S. crude oil cannot legally be exported, SPR supplies will typically only displace seaborne imports.

U.S. crude oil imports into the Gulf Coast region, known as Padd 3, fell 8 percent last year to below 5 million bpd, the lowest level since the 1990s.

Last year, at least some of the crude released from the SPR traveled further afield, beyond the Gulf Coast.

Tesoro, whose only refineries are on the West Coast, bought 1.2 million barrels, while East Coast refiner Sunoco bought 1.4 million barrels. Obama issued 44 waivers to the Jones Act to allow companies to use non-U.S. tankers for shipments last year.

But the East Coast looks a less likely market this year. Sunoco is set to close its 335,000 bpd Philadelphia refinery before June if it does not find a buyer. That could cut the region’s capacity to less than 700,000 bpd.

Ultimately the rate of release means little if you cannot get the oil quickly to those who need it most, says Mark Routt, a senior oil market consultant at KBR Advanced Technologies.

“To say that you have this drawdown capability, but you’re putting oil in places it doesn’t need to go, isn’t really helpful to the market,” Routt said.

(Editing by Russell Blinch and Jonathan Leff)

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Permian Basin of West Texas seeing oil boom

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DALLAS — The Permian Basin of West Texas is experiencing an oil boom, leading some of the region’s top oilmen to predict that Texas oil production will double within five to seven years.

Oil drillers over the last eight years have found that the dense oil rock of the basin surrounding Midland and Odessa responds well to hydraulic fracturing, releasing lush yields. Total oil production last year in Texas averaged more than 1 million barrels per day for the first time since 2001.

“Right in the basin, we could get up to 2 million barrels a day,” Jim Henry of Midland-based Henry Resources told The Dallas Morning News for an article in its Sunday’s edition.

“I’ve been totally surprised by the amount of oil we’re finding out in the shale zones,” Scott Sheffield, chairman and chief executive of Irving-based Pioneer Natural Resources Co., told the newspaper.

“We have 30 billion barrels of new oil discoveries,” said Tim Leach, chairman and CEO of Midland-based Concho Resources. “It can be hard to get your mind around that.

The cloud on the horizon is the persistent drought that has gripped the region. Hydraulic fracturing, or “fracking,” requires massive amounts of water to pump into the ground under high pressure.

Drillers also worry about the prospect of tax increases and limits placed on land use by the presence of such endangered species as the dunes sagebrush lizard.

But as long as crude oil prices remain high, around $100 per barrel, drilling will remain profitable.

Similar booms are under way in the Eagle Ford Shale of South Texas and the Bakken Shale of North Dakota and Montana. Production also is climbing rapidly in western Alberta Canada, which is now the largest source of U.S. oil imports.

“I could paint a scenario for you where we are producing 3 million more barrels per day by 2016, which would almost get us to the point where we could eliminate 60 to 70 percent of our OPEC imports,” Texas Railroad Commissioner Barry Smitherman told The News. “With that greater control over our own energy security, we could care less about what happens in the Strait of Hormuz.”

The narrow straight between the United Arab Emirates and Iran is considered strategically vulnerable to blockade by Iran’s revolutionary regime.

The United States still imports 45 percent of the 19 million barrels of petroleum that it consumes, but that is a sharp reduction, according to the U.S. Energy Information Administration. In 2005, about two-thirds of all liquid fuels the United States consumed was imported.

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