Posted on 01/28/2014 5:58:07 AM PST by thackney
When the Cline Shale first moved into the public eye a couple of years ago, the West Texas play quickly set aflame industry’s imagination of a Saudi Arabia-like reservoir that would provide tens of billions of barrels of crude for the oil-hungry US market.
“Shale oil field 3 times bigger than the Eagle Ford (and 6x bigger than the Bakken),” read one headline. “Cline Shale could be biggest in US history,” read another.
But the Cline, alone, has not yet lived up to the hype, although exploration there is still in its infancy compared to the slightly more mature and greatly prolific Wolfcamp formations above it.
So, does the Cline contain the 30 billion barrels of recoverable oil that was widely-touted in the press?
“I don’t think we would agree that’s a viable number,” Benjamin Shattuck, research analyst at energy consultants Wood Mackenzie, said. “Twelve to 18 months ago, the Cline was the next big thing. But the data just wasn’t there to support it.”
While some operators have had some success, that has been confined to “a very limited scope of the play,” Shattuck said. “So far variability has been high and results not that great, and at the same time, results improving in the Wolfcamp to the west.”
But the Cline could likely be an adjunct to the Wolfcamp, analysts say. “I’d definitely say it looks hopeful at this point,” Tom Tunstall, research director for the Institute for Economic Development at the University of Texas-San Antonio, said of the formation.
Wells in the Cline—which is sometimes referred to as the Wolfcamp D zone—certainly appear to have potential. For example, one recent Cline well drilled by Pioneer Natural Resources, the University 7-43 10H, debuted at a stunning 3,605 b/d of oil equivalent in its first 24 hours.
Pioneer touted the well, sited in Andrews County about 60 miles northwest of several other Cline wells drilled in Glasscock County, as showing “the best initial production of any Midland Basin interval.”
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Located around 9,000-10,000 feet deep in a ghost-shaped spread, the Cline is one of the deepest of at least a dozen productive “stacked” or layered formations that have been drilled in the Permian. It spans several counties in the Midland sub-basin of the eastern Permian and is said to be 250-plus feet thick.
Big independent Devon Energy prominently brought the Cline to industry’s notice two years ago during a quarterly conference call. But last August, company officials said they had decreased rig activity there after seeing “a lot of variability” in the formation. At the time, the company was running two Cline rigs, both of which would drill what Devon Executive Vice President of Exploration and Production Dave Hager called “mini-developments” in Sterling County, “seeing how low we can get well costs to have economic developments there. …We need to do some studying before we go back out there with a significant program.”
Javan Ottoson, president and chief operating officer for Denver-based SM Energy, said in a recent conference call that these are early days for the Cline.
“There’s no question that some of the…early vertical wells didn’t go quite as deep the way that play worked out,” Ottoson said. SM plans to drill the Cline this year, mainly because its depth would allow the company to hold the acreage by production, preventing expiration of the leases.
Because operators that produce the Cline are typically also drilling the Wolfcamp horizons above it, it is difficult to separate out just how much oil the formation alone produces or could produce. Analysts say that at the very least, industry needs to understand the zone better.
Because it is relatively deep within the Permian, operators say accessing the Cline can add as much as $1 million more to drilling costs than a typical Wolfcamp well. But recent operator comments show industry still appears enthused over its potential.
For example, Range Resources has drilled a Cline well, “which we’re really encouraged by,” Chief Operating Officer and Senior Vice President Ray Walker said during the company’s Q3 conference call. “We haven’t seen any of the wells clean up like this [so]early.”
Big Permian operator Apache is focusing on Glasscock County, which is also seen by other operators as the heart of the play; the company, which holds holds 520,000 net Cline acres, claims to be the leading Glasscock Cline player with about 40 horizontal wells last year.
Apache also said play is yielding what it characterized as “increasing estimated ultimate recoveries with additional frac [fracture-stimulation] stages, changing frac design and optimized landing points.”
“We are still on a learning curve in the Permian Basin,” Apache CEO Steve Farris said.—
Trust me, if it’s there, we’ll get it, and we’ll find a way to get it cheaply. That’s how Americans do things, with or without the creep in the White House.
A real nice thing about the Permian basin is that most of the necessary oil transportation infrastructure is already in place. That alone will decrease the final costs in these new developments.
Along with all the other infrastructure and housing.
“We are still on a learning curve in the Permian Basin,” Apache CEO Steve Farris said.—
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I think this about calls it.
Current frustrations in the Permian remind me of the talk 2-3 years ago in the Niobrara—especially that area in the northeastern section of colorado. They subsequently figured out the geology and now 4-5 companies in production.
So add geological uncertainty to low horizontal rig count as reasons the Permian production has not accelerated.
Then check back in two-three years.
There are 237 Horizontal Rigs actively drilling in the Permian Basin. There are another 28 directional drilling rigs actively working.
Room to grow is not the same as a low count.
http://gis.bakerhughesdirect.com/RigCounts/default2.aspx
At the following link select “Trajectory” from the legend on the left and “Permian” in the basins at the bottom.
For comparison, DJ and the Niobrara combined have 54 horizontal and directional drill rigs active. Eagle Ford has 198, Wilston (Bakken) has 176.
I don’t see how to consider the Permian being a low horizontal rig count.
your last post on this question said that the permian basin moved to 35% horizontal drills. This year they expected to go to 50% horizontal rigs.
The niobrara production zones would be 100% horizontal drills
“Room to grow is not the same as a low count.” Agree on this.
So it may well be that the problem in the Permian is that they have not figured out where the sweet spots are as they have in the Niobrara, the Baaken and the Eagle Ford...and some parts of the Woodford. They have not figured out where to place platforms so that they are perfectly situated over multiple deep oil layers that they can frack from the same platform. Consequently the horizontal drilling rigs are not put to their best advantage.
I think you are assuming a lot.
I think a better answer is that in the Permian Basin, there is plenty of places where cheaper vertical drilling produces enough economic production of oil, that the higher dollars for horizontal well development are not always needed.
Remember the real goal of an oil company is to produce the highest ratio of dollars out for dollars in. It is not to produce the highest ratio of oil out for wells drilled.
Remember the real goal of an oil company is to produce the highest ratio of dollars out for dollars in. It is not to produce the highest ratio of oil out for wells drilled.
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well this is true.
however, we were shown a graph not long ago that drilling costs in the woodford formation in oklahoma and the permian basin in texas were the highest in the $90@ barrel range.
It was totally counter intuitive. the baaken oil was cheaper than the permian basin oil?
why
well one reason for this is several innovations that have come to the baaken —but not the permian basin— lately including one where they have one pad that will support several dozen wells drilling and fracking in different directions at different depths. This lowers the cost of the per well drilling and kills the meaning of the rig count. this is only half the story. the other half is that they have moved from exploration in the baaken ... to production. that means that they have thoroughly mapped the underground structures and have figured out precisely where to place the rigs so as to enable the most drills to drill profitably. not an easy thing to do. just because they have horizontal drilling rigs in place does not mean they have them in the best locations. that takes time to figure out. that’s why the permian basin is still in the exploratory phase and the baaken is in the production phase.
a caveat here. there are some new deeper structures in the baaken three forks basement that continental has recently drilled through and found to be profitable — that are not yet in production phase.
Why would you assume Permian shale oil to be cheaper to drill than the Bakken? Shale formations have lots of variations.
It was totally counter intuitive. the baaken oil was cheaper than the permian basin oil?
Why would you assume Permian shale oil to be cheaper to drill than the Bakken? Shale formations have lots of variations.
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True. I’m just talking superficial reputations. Persumably the permian basin oil was mostly not horizontally drilled and thus less expensive.
I was trying to find that link about drilling cost we discussed before. Do you have that handy?
if you posted the drilling costs link, then do a search on thackney in the search bar. be sure to click on “users”. You’ll see everything you’ve posted. Then just go back through your posts.
I wouldn’t mind seeing that link again.
I have searched a couple ways.
No luck so far.
do you recall the title of the article or any of the words in the article? or the magazine it was written in?
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