Posted on 10/26/2013 9:08:42 PM PDT by ckilmer
SmallerLarger Share on email Share on print More Sharing Services Expand Photo A cloud formation fills the sky as an oil pump is silhouetted in front of it near the town of Hereford on the northeastern plains of Weld County. Drilling operations throughout northern Colorado are suspected to only have tapped into a fraction of the oil and natural gas in the region. Tribune file photo |
A cloud formation fills the sky as an oil pump is silhouetted in front of it near the town of Hereford on the northeastern plains of Weld County. Drilling operations throughout northern Colorado are suspected to only have tapped into a fraction of the oil and natural gas in the region. Expand Photo An oil and gas worker helps operate a drill high off the ground south of LaSalle. New techniques in fracking have helped oil and gas companies safely reach oil deposits throughout northern Colorado. Tribune file photo |
An oil and gas worker helps operate a drill high off the ground south of LaSalle. New techniques in fracking have helped oil and gas companies safely reach oil deposits throughout northern Colorado. Expand Photo Cut of soil columns (profile). Getty Images/iStockphoto | iStockphoto
Cut of soil columns (profile). Expand Photo
Expand Photo A cloud formation fills the sky as a oil pump is silhouetted in front of it near the town of Hereford on the eastern plains of Weld County. Drilling operations throughout northern Colorado are suspected to only have tapped into a fraction of the oil in the region. Tribune file photo |
A cloud formation fills the sky as a oil pump is silhouetted in front of it near the town of Hereford on the eastern plains of Weld County. Drilling operations throughout northern Colorado are suspected to only have tapped into a fraction of the oil in the region. Expand Photo
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Cut of soil columns (profile).
With each tweak of technology, the rigs keep coming, and the oil keeps flowing in Weld County. For some, that’s a combination unlike any other in these days of high stakes energy security and independence.
Every year, companies dig deeper into the mysteries beneath the surface coming away with more clues to unlocking the code that releases the rich resources in the Wattenberg Field and emerging sweet spots in northeastern DJ Basin.
As the companies continue to improve their frack formulas or completion methods or improve drilling times, the game changes just as fast, as more resources are uncovered all the time, giving the Wattenberg an even longer shelf life.
“Our Wattenberg horizontal program significantly prolonged the life of a field that has been producing for more than 40 years,” said John Ford, manager of the Wattenberg program for Anadarko Petroleum Corp. “It’s astonishing that technology can continue to enhance the value of oil and natural gas basins throughout the United States, and in the case of the Wattenberg, deliver a billion-barrel-plus field, well into its productive life.”
Michael Starzer, CEO of Bonanza Creek Energy, which has 500 wells drilled in the Wattenberg and the outskirts, agreed: “The Wattenberg is called ‘Old Reliable.’ With these advances in technology that keep accelerating, I feel pretty comfortable in saying 30 years from now, we’ll still be talking about the Wattenberg.”
As the plays progress, oil and gas companies are investing more in the field and its perimeter every year, dumping in some cases billions into their drilling programs in the basin. Noble Energy and Anadarko, the top two drillers in the field, have combined plans to drill more than 800 wells next year.
Some estimates show there could be as much as 4 billion barrels of oil locked into the tight rock formations called the Niobrara and Codell, and to date, drillers have barely tapped 20 percent of what’s down there, some figure.
“I’ve heard estimates that in the last big rush in the ‘90s, they left 90 percent of the reserve in the ground,” said Tommy Holton, a member of the Colorado Oil and Gas Conservation Commission. “We’re not getting it all. With technology, we’ll get to that point. As far as the product going away, that’s not going to happen.”
The U.S. Energy Information Administration reports that in 2011, the latest numbers available, proved reserves of oil in the United States grew to the highest level since 1985.
“Proved oil reserves, including both crude oil and lease condensate, increased by 15 percent in 2011 to 29 billion barrels, marking the third consecutive annual increase and the highest volume of proved reserves since 1985,” the EIA reported Aug. 1. “Proved reserves in tight oil plays accounted for 3.6 billion barrels (13 percent) of total proved reserves of crude oil and lease condensate in 2011.”
Proved reserves in shale gas plays accounted for 131.6 trillion cubic feet (38 percent) of total proved reserves of wet natural gas in 2011, the EIA reported.
The agency expects oil production across the country to increase to 7.8 million barrels of oil per day by 2014, which would be the highest annual average level of production since 1988. In the next decade, the EIA figures tight oil shale will “rise sharply.” That dovetails with the EIA expectation that world energy consumption will increase by 56 percent in by 2040.
Pete Stark, an analyst with IHS in Denver, said people laughed at him in 2010 when he said the Niobrara and the DJ Basin, alone, had the potential for 2 billion barrels of oil. He’s upped that to more than 4 billion barrels today.
“That’s humongous,” Stark said. “The biggest onshore U.S. discovery since Prudhoe Bay until the Bakken ... was 175,000 barrels in Utah, and everyone said, ‘Oh, hallelujah.’ ”
“We’ve had a step change in the learning curve that essentially moves the Niobrara and the DJ Basin from being a good regional play into one of the top five or six tight oil plays in the country,” Stark said.
Gift that keeps on giving
Oil and gas drilling has been a staple of Weld County in northern Colorado since the gas-rich Wattenberg Field was discovered in 1970 — it’s considered the most important discovery in Colorado in the last 50 years. The oil and gas industry’s foray into northern Colorado has continually improved since the 1970s discoveries and vertical drilling.
In the ‘80s, drillers tapped into the Codell and Niobrara formations vertically. The ‘90s, brought on the Dakota, the deepest of the formations in the basin at 7,800 feet — 1,000 feet below the now prolific Niobrara.
Producers use lessons learned in drilling the Bakken, which has been drilled since 2000, and used them to improve methods in Colorado drilling today. Through the years, discoveries, different spacing and refracking wells kept the field humming.
“I don’t think anyone at the time saw the potential application to the Niobrara,” Starzer said. “A few wells were drilled horizontally, but completions weren’t as successful as they are today.”
The Jake well, drilled in late 2009 by EOG Resources near the Wyoming border, was the first example to companies that horizontal drilling coupled with long-held practice of hydraulic fracturing was the skeleton key to unlock the resources.
“The Wattenberg field has had many lives,” said Steve Sonnenberg, a professor of petroleum geology at the Colorado School of Mines, who has studied the Wattenberg for 35 years.
“Here’s the amazing thing. If you look at production now, here’s a field discovered in 1970, so over 40 years ago, and it’s at peak production now,” Sonnenberg said. “Normally, after 30 years, it’s close to the end.”
Until the most recent renaissance, Stark said U.S. oil production had really been on the downward trend since the ‘70s.
“Everyone said, ‘Hey, North America, it’s old hat, old news,” Stark said. “There’s nothing new here, and voila, the combination of horizontal wells and the ability to use multistage fracking have enabled the industry to break the code on producing huge new volumes of oil that have always been there, but just couldn’t get to.”
No fluke
Jake’s production of 645 barrels of oil equivalent a day on a 30-day average at first seemed like a fluke, as many other drillers couldn’t repeat those results.
Some drillers at first weren’t in the right spots, experts say, which contributed to a shaky beginning.
But once they found the sweet spots, the entire landscape changed. Last year, Encana, for example had a well that averaged 834 barrels of oil equivalent per day; another one came in at an average of 907 BOE in that 30-day average.
“We’re in the early stages of the development activities, even though this started in 2008, and things were still being delineated,” Sonnenberg said. “A year from now, we’ll be much wiser about the size and shape of this potential resource. At this stage, the Wattenberg looks really good.”
Oil production out of Weld County, which is blanketed by the DJ Basin, has grown dramatically. From Jake’s arrival to 2012, production increased 76 percent to 36.7 million barrels. It also grew as a percentage of the state’s production to 74 percent in 2012, up from 63 percent in 2010. The state in 2012 broke a 50-year-old production record, as well. It just keeps growing.
The Wattenberg is certainly not the most prolific of the U.S. plays (it could easily sit as the No. 5 behind plays in Texas and North Dakota), and it is still in its early days with companies refining their patterns of downspacing, drilling time, frack fluids and completion methods to create the most ideal and cost-effective drilling solution.
But, the Niobrara is fast becoming the most economical. Companies are driving down drilling costs every day with increased experience, technology and trial and error.
Costs to drill horizontal wells are still around $7 million to $9 million in the Bakken formations in North Dakota. In Colorado, many companies have brought those costs down to the $4 million to $5 million range — one of the chief reasons companies are investing in the state.
“When you look at it costing them roughly $1 million per thousand feet, when you’re talking about dumping that kind of money into one well, they wouldn’t do it unless there was a huge payback,” Holton said. “A study I saw said that every horizontal well will pay out $1.5 million over a five-year period just in royalties.”
Brad Holly, vice president of the Rockies Division for Anadarko, said the big game changers are probably over for now. Companies will continue to refine the process to further drive down production costs.
“We just drilled a well in the Wattenberg, that went from spudding to rig release is six days. We won’t see huge game-changing improvements, but there always enough steps in the process to continue to drive that down,” Holly said. “We don’t have a goal per say, but we’ll continue to drive those efficiencies.”
Game changing environment
Technology, technique and time has evolved so that exploration and production companies could be working for 20 more years just to unlock the code to producing it – then comes years of production.
“I’d say the evolution of technologies has really made this opportunity present itself,” Sonnenberg said. “It’s not part of the boom and bust. Really, it’s all about technology. You weren’t able to do this back in 1970. That’s was not possible.”
Vertical drilling really only allowed companies to hit one formation at one point in the rock. Horizontal drilling has increased the resource potential exponentially, by allowing drillers to frack the rock bed in several spots, all from one well bore.
Companies are experimenting with multiple zone development that will likely keep the DJ basin prolific for years into the future.
The three different benches of the Niobrara, plus the Codell, are being drilled in varies couplings.
“A year go, the Niobrara play essentially was focused around the Niobrara B zone,” Stark said. “In the last year, the companies have also learned they can economically produce in parts of the fairway, the Niobrara A, C, and also the Codell. All four of those zones are potentially commercial reservoirs in their own right.”
All of the majors, Stark said, are experimenting with well spacing and number of wells they can drill from a single pad.
“There’s probably no single cookie-cutter pattern that will work best everywhere,” Stark said. “In some cases it will be B and A, then B and C and Codell. … It could be 16-32 wells drilled from each pad.”
The experimentation will mean efficiencies in the long run. “It’ll make costs lower, the environmental impacts will be lower and when they optimize those per well, all of those parameters will decrease over time.”
Stark said that could mean another 15 years of drilling into the future. Then comes production.
“They’ll still be drilling 20 years from now, probably,” Stark said.
The result is continually increased production levels out of the Niobrara, which companies are changing all the time. The Niobrara could reach as high as 400,000 to 500,000 barrels of oil equivalent per day.
At present, Anadarko and Noble are bringing in almost half that, and they’re still adjusting up their numbers higher every quarter as they hit new milestones. Just last fall, Anadarko hit the 100,000 barrel-a-day milestone.
“It will be a continually evolving process,” Stark said. “Not all of the potential or prospective Niobrara has been tested. Probably 50 percent of the Niobrara fairway has been tested, 50 percent has not. That part hasn’t been fully tested, and it’s certainly perceived by what we know now to be a higher risk and less favorable overall geological characteristics, but it’s certainly not condemned. … The point is we’re in a game-changer era.”
Ford at Anadarko agreed: “We love the Wattenberg Field. If you were drawing up the ideal place to produce, you would want a large resource base, large acreage position, knowledge of the basin, extensive infrastructure, access to qualified workers, year of experience and lower-cost wells.
“The Wattenberg has all of these elements.... In Anadarko’s worldwide portfolio, the Wattenberg horizontal program is one of our best investment opportunities.” •
Interesting post, to be read later.
Thanks ckilmer.
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