It’s clear from comments on Q2 conference calls in the last week that North American producers ARE getting more efficient—lowering costs—in producing tight oil, or shale oil. And they don’t think they’ve hit their limits yet.
The high tech reason for these improvements? Simple sand. It is stunning to me how much more sand is getting used in tight oil and gas wells.
Here’s a chart from US Silica (SLCA-NYSE) on what it takes to frack a single well now:
And here is another visual from energy boutique brokerage firm Tudor Pickering & Holt on where they think frac sand use is going next year in the Permian basin of SW Texas:
They have a near identical chart for the western Delaware basin of the Permian.
Cimarex (XEC-NYSE) said on their Q2 call on Thursday Aug. 4 that they increased their sand or “proppant” use by 92% to 2400 pounds every linear foot of a 10,000 foot horizontal in a Lower Wolfcamp formation well in Culberson County and increased production 36%. Here’s a slide that shows how much more sand they use now just over the last 18 months:
Here’s what Devon Energy (DVN-NYSE) said in their Q2 call last week:
“John P. Herrlin – SG Americas Securities LLC
…with the STACK and also the Woodford, you’re putting in a lot more sand. Do you have any sense of what you think the economic limit is for how much profit you can put in?
Tony D. Vaughn – Chief Operating Officer
I can give you a little bit of a feel. I’ll remind us of the experience that we had in, I believe it was mid-2014 when we started increasing the sand loads in our Delaware completions and we really ran up to – from about 600 pounds per lateral foot in early 2014 up to about 3,000 pounds per lateral foot through 2015…We think we can get the most commercial returns in the current business environment done at about 1,500 to 2,000
“..And then if you move over into the Anadarko Basin, we’re using a slick water job in our Woodford type work, and we continue to increase our proppant loads there. So we’re up to about 2,000 pounds per lateral foot. And after drilling and completing over 800 wells, this last large pad that we brought on had the best results that we’ve ever had in the Cana-Woodford play.
“As we think about the STACK play right now… we are increasing our sand loads there up to about 2,600 to 2,750 pounds per lateral foot and enjoying increasing success there.” (Courtesy of SeekingAlpha.com)
Chesapeake (CHK-NYSE)—never a company to do things in a small way—has the biggest frack I’ve heard of so far. They put more than 30 million pounds into a Haynesville shale—and the CEO Robert Lawlor said on the Friday Aug. 5 conference call that more sand is so good, he calls drilling now “proppant-geddon’:
“The results have been very impressive, with the restricted initial rate of 38 MMcf/d and a flowing pressure of approximately 7,500 psi,” Lawler said. “We call this new era in completion technology, ‘proppant-geddon.’
“We’ve not yet reached the point of diminishing returns in the Haynesville, and we plan additional tests up to 50 million pounds in the back half of the year.”
No wonder the stock of US Silica has gone from $16-$40 this year—and stayed there.
There’s a couple points here for investors. Data on how much oil and gas producers are getting per 1000 feet is not easy to come by. But several presentations are now showing over 3bcf/1000 feet for natural gas—that’s very impressive.
And I am reading regularly that stretching laterals from 1.5 – 2.0 miles only costs an extra 20%, to get 50% more production.
The point is—economies of scale are absolutely creating lower costs per barrel. And producers would not be increasing sand use 40% if that wasn’t happening.
Second, not only is an incredible amount of sand being used now, the mix in sand is changing. The Market at first used mostly coarse sand, but is now using a finer mesh. And because margins are being squeezed everywhere, producers are finding this method cheaper.
“All the operators are using the slick water completion method,” says Rasool Mohammad, CEO of Select Sands (SNS-TSXv), which is developing a sand deposit in Oklahoma. “This is cheaper than the cross gel which uses expensive frack fluids. And the slick water primarily uses finer grade sands, 40-70 and 100 mesh.”
Mohammad—who is actually selling sand to industrial users outside of energy—says the coarse sand actually does do a better job in the long run, but right now cheaper costs are the most important factor for producers.
That cost cutting is causing the industry—and that means producers, specialty frac sand suppliers like US Silica and the big service companies like Halliburton & Schlumberger etc.—to start looking at regional sand deposits in the southern US. Traditionally, very high quality white sand, mostly from Wisconsin, has been used.
But transport costs can be high, and companies like US Silica are now buying brown sand deposits closer to Texas, where it looks like the Permian will be the most active light oil basin in North America.
Mohammad’s sand has all the technical and logistical wants by the majors, and he is hopeful to land his first energy sales contract this fall.
The Market is convinced there will be no more price concessions by sand suppliers, and Mohammad believes there may even be a shortage of the finer sand like the one in his deposit by Q1 2017. The industry has built and relied on the white coarser sand for the last 7 years of the Shale Revolution; this finer part of the market has been ignored and now is suddenly in high demand.http://oilandgas-investments.com/2016/latest-reports/the-1-efficiency-gains-in-energy-come-fromsand/