US oil production grew more in 2012 than in any year in the history of the domestic oil industry back to the Civil War
From Saturday’s WSJ:
U.S. oil production grew more in 2012 than in any year in the history of the domestic industry, which began in 1859, and is set to surge even more in 2013. Daily crude output averaged 6.4 million barrels a day last year, up a record 779,000 barrels a day from 2011 and hitting a 15-year high, according to the American Petroleum Institute (API), a trade group. It is the biggest annual jump in production since Edwin Drake drilled the first commercial oil well in Titusville, Pa., two years before the Civil War began (see chart above).
The U.S. Energy Information Administration predicts 2013 will be an even bigger year, with average daily production expected to jump by 900,000 barrels a day. The surge comes thanks to a relatively recent combination of technologies—horizontal drilling and hydraulic fracturing, or fracking, which involves pumping water, chemicals and sand at high pressures to break apart underground rock formations.
Together, they have unlocked deposits of oil and gas trapped in formations previously thought to be unreachable.
That has meant a resurgence of activity in well-established oil regions, such as West Texas’s Permian basin, as well as huge expansions in areas that had been lightly tapped in the past, such as North Dakota’s Bakken shale region. The Bakken has gone from producing just 125,000 barrels of oil a day five years ago to nearly 750,000 barrels a day today.
The benefits of the surge in domestic energy production include improving employment in some regions and a rebound in U.S.-based manufacturing.
MP: Actually, the API’s estimate of a 779,000 barrel per day (bpd) increase in domestic oil last year is pretty conservative compared to year-end comparisons of EIA data for weekly US oil production. Compared to oil output at the end of 2011 (5.846 million bpd), US oil production increased by 1.139 million bpd last year to almost 7 million bpd during the last week of December 2012. Alternatively, using the EIA’s four-week production averages show an increase of 1.063 million bpd from December of 2011 to December 2012. The reason that the yearend comparison shows a much higher annual increase in US oil production (about 1 million bpd vs. 779,000 bpd) is that domestic oil production accelerated during the second of last year – crude oil output increased 14.6% during the second half of 2012 compared to the 4.2% increase during the first six months.
The record increase in oil output last year reminds us the US oil and gas industry continues to be at the forefront of the otherwise sub-par economic recovery, and without that sector’s strong growth in output and jobs, the economy’s sub-par performance would be even more lackluster. The 1 million bpd increase in domestic oil production last year has delivered a powerful energy-based economic stimulus to the economy, creating thousands of new direct, shovel-ready jobs in oil and gas activities, and igniting many spinoff business and indirect jobs throughout the oil and gas supply chain like the “oil-by-rail shipping boom.” The future of the US economy over the next few years looks a lot brighter because of America’s surging domestic energy production.
- US oil production grew more in 2012 than in any year in the history of the domestic oil industry back to the Civil War (aei-ideas.org)
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By Vicki Vaughan
The report, from information and analytics firm IHS, looked at well performance for oil and oil-rich liquids in the Eagle Ford as well as in the Bakken Shale of North Dakota and Montana, currently the nation’s top play. The Bakken has more wells than the Eagle Ford, but so far, on a per-well basis, the Eagle Ford seems to be producing more than the Bakken.
The Bakken is more established, and the Eagle Ford is still developing.South Texas
This IHS report is part of a broader study that’s under way of 27 of the nation’s shale plays.
The IHS analysis shows that “Eagle Ford drilling results appear to be superior to those of the Bakken,” said Andrew Byrne, director of equity research at IHS and the study’s author.
The Bakken shale is the play against which others are measured, Byrne said, because “it was the key play that really opened up development of unconventional resources” using high-tech drilling methods and hydraulic fracturing.
The Bakken first began to show great promise about 12 years ago, Byrne said.
“The results from the Bakken were so strong that it set the standard by which all others will be measured. It was the one play that incited the industry into pursuing these opportunities,” he said.
Now, though, comes the Eagle Ford.
Wells in the Eagle Ford Shale have a stronger flow – 300 to 600 barrels a day or oil and oil-rich liquids, based on average production in a peak month – than in the Bakken, where flow ranges from 150 to 300 barrels a day.
“One of the reasons we really like the Eagle Ford is its potential as a large total resource. It could be one of the best, if not the best, in North America,” Byrne said.
“The Eagle Ford covers such a vast area. That also makes this such a strong play.”
The Eagle Ford sweeps 400 miles from East Texas to counties south of San Antonio and on to the border.
The play “gets uniformly strong results, and that’s making the play look that much bigger and better,” Byrne said.
“All plays essentially have sweet spots. What makes the Eagle Ford so good is that the noncore stuff is delivering strong results also. In some other plays, it’s only the sweet spot that’s economic.”
The Center for Community and Business Research at the University of Texas at San Antonio has also prepared studies of the Eagle Ford Shale. Center Director Thomas Tunstall predicts that the Eagle Ford Shale will produce 65 million barrels of oil for 2012. Oil production in the Eagle Ford reached 36.6 million barrels in 2011, according to Texas Railroad Commission data.
It’s somewhat difficult to predict production from the shale because the rate of production is accelerating, Tunstall said.
IHS doesn’t yet have an estimate of all the oil that is in the Eagle Ford.
“We’re working on that,” Byrne said.
Last week, Steve Trammel, senior manager of industry affairs for HIS, said in an interview that rig counts are declining in shale plays with much more natural gas than oil because of low natural gas prices.
But drilling is on the rise in shale with oil and “liquids-rich” areas, where wells can tap a mix of oil and condensate, a light oil, and “wet,” or liquid, natural gas, Trammel said.
In fact, the highest average monthly production in the Eagle Ford is coming from the formation’s liquids-rich window, Byrne said.
Asked which might be the next hot play, Byrne said: “We haven’t officially put out that opinion yet. That will have to be reserved until we finish our study.”
The energy industry is “very creative,” he noted. “It seems like every quarter another play shows up.”
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Drilling in the Eagle Ford shale has dramatically increased in 2012, as producers have frantically turned away from cheap natural gas to production from regions that yield higher priced oils and other liquids.
The number of new wells drilled in Texas’ Eagle Ford shale more than doubled during the first three months of 2012, compared with the same period a year ago, according to Bentek Energy.
Operators started 856 new wells in the first quarter of 2012, compared with 407 in the same period a year ago, the energy market analysis firm reported.
There was also a record high number of 217 rigs active in the Eagle Ford during this month.
The increase in activity ratcheted up production of oil and other liquids, from 182,000-barrels-a-day in April 2011 to more than 500,000-barrels-a-day this month, according to Bentek’s analysis, which the U.S. Energy Information Administration highlighted on its website.
The Eagle Ford currently produces about 2 billion cubic feet of natural gas per day.
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By Edward Klump – Mar 22, 2012 7:00 PM CT
Energy companies in search of oil riches rivaling the biggest finds from Brazil to Angola are flocking to Texas shale, where new wells have triggered a 230- fold increase in crude output in three years
More than 115 years after a gusher 55 miles (88 kilometers) south of Dallas ushered in Texas’ first oil boom, U.S. producers such as ConocoPhillips and Marathon Oil Corp. (MRO) are counting on the Eagle Ford Shale to boost crude output amid a glut-driven slump in natural-gas prices.
Drilling for oil in the brush-covered plains of south Texas is cheaper and less risky than exploration offshore Brazil, the largest oil find in the Western Hemisphere in 30 years, and more profitable than the remote, rougher terrain of the Bakken Shale in North Dakota and Montana.
“The Eagle Ford is the top basin we have in the world today,” David Roberts, chief operating officer at Marathon Oil, told analysts and investors on a conference call last month.
Surging production in shale formations has transformed the U.S. energy landscape, flooding the market with gas and boosting domestic oil production by 14 percent from three years ago after dropping by a third in the previous 17 years, according to Energy Department data. After worries of a global oil shortage drove prices to record highs above $140 a barrel in 2008, politicians and industry executives now are discussing the prospect of the U.S. weaning itself from dependence on imports.
Marathon Oil and ConocoPhillips (COP) both plan to double their production in the Eagle Ford this year. EOG Resources Inc. (EOG), based in Houston, calls the Texas shale play its biggest source of growth, and last month boosted its estimated recoverable reserves there by 78 percent.
Oil production in the Eagle Ford jumped almost sevenfold in 2011 to surpass 30 million barrels, still less than Bakken production in North Dakota that exceeded 128 million barrels. This year daily oil production in the Eagle Ford is forecast to expand by 200,000 barrels, roughly the same amount as the Bakken, according to estimates by Wood Mackenzie Ltd. cited by Hill Vaden, an analyst with the industry consultant.
The South Texas oil fields are winning a larger portion of producers’ investment because it’s easier and more profitable to drill there compared to many prospects in the U.S. and in the world. Wells are faster and cheaper to develop, and the formation is located closer to refineries on the U.S. Gulf Coast, lowering transportation costs.
EOG said it costs about $5.5 million per well in the Eagle Ford, compared with more than $8 million per well in the Bakken, because of different well configurations. An offshore Gulf of Mexico well can cost $100 million, said Brian Uhlmer, an analyst at Global Hunter Securities LLC in Houston.
Deep-water wells can take five months or longer to drill, compared to a couple of weeks for a well in the Eagle Ford, said Brian Cain, a spokesman for Anadarko Petroleum Corp. (APC)
Producers can get a higher price for their Eagle Ford output than they can in the Bakken. Prices for Texas and Louisiana (USCRLLSS) crude this week are as much as about $38 a barrel more than production in the Bakken (USCRLLSS), according to data compiled by Bloomberg.
“The economics there are absolutely stellar,” said Danny Brown, a general manager who helps oversee Anadarko’s Eagle Ford operations. Anadarko has said it is considering selling its exploration properties offshore Brazil.
Less Political Risk
Texas provides a more stable investment environment compared to many international projects, said Pavel Molchanov, an analyst at Raymond James & Associates in Houston.
“Clearly, there’s less political risk in Texas than in Libya, let’s say, or Kurdistan,” he said. Marathon Oil last year had output suspended in Libya during unrest in that country.
The Eagle Ford cuts across a 400-mile swath of southern Texas, according to the Railroad Commission, which regulates oil and gas production in the state. Producers have unlocked the resource using advances in horizontal drilling and hydraulic fracturing, which sends jets of water, sand and chemicals underground to break up rock.
Petrohawk Energy Corp., acquired by BHP Billiton Ltd. (BHP) last year, first drew attention to the Eagle Ford when it announced a gas find in 2008, a year when futures for the fuel in New York averaged more than $8 per million British thermal units.
Expanded use of fracturing, or fracking, across the U.S. caused a surge in gas output that drove prices to a 10-year low this month of $2.204 per million Btu. Meanwhile, crude in New York has climbed 15 percent since the end of 2010 and is trading for about $105 a barrel.
The Eagle Ford will help lead a surge in state drilling permits that’s on pace to reach 25,000 this year, the most since 1985, said Barry Smitherman, the commission’s chairman.
“It’s by far the most sought-after play anywhere — not only in this country, but anywhere around the world,” said Fadel Gheit, an analyst at Oppenheimer & Co. in New York.
A Sanford C. Bernstein report last August estimated Eagle Ford production would reach 1.2 million barrels of oil equivalent a day in 2015, with 750,000 of that being liquids.
“A long-time oil field axiom is that big fields tend to get bigger over time, and that’s certainly the case here,” EOG Chief Executive Officer Mark Papa told investors during a Feb. 17 conference call. “This continues to be the hottest and highest reinvestment rate-of-return play in North America.”
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(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)
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