The US and Canada aren’t slowing oil production, as many predicted when it appeared oil prices were settling into a lower pattern for an extended time period. Efficiencies, which fostered the growth of tight oil production, have continued to protect margins, as Benjamin Morse and Starr Spencer explain in this week’s Oilgram News column, New Frontier.
When OPEC left production unchanged in November last year many understood it to be US or Canadian tight oil producers who would suffer, but thanks to technological advances — to paraphrase Mark Twain — the reports of the death of the tight boom have been greatly exaggerated.
After OPEC’s announcement of stable production, crude prices fell under $50/b, and the obituaries began to be written.
But lower prices forced companies to become hyper-vigilant on costs, and the result was the opposite of what may have been intended. US and Canadian production continued to grow, and E&P companies became leaner and more efficient — leading to a more competitive industry.
The savings from technological advances and more efficient internal processes, unlike the drop in rig dayrates that could rise again when the market turns, will be a more permanent feature of the North American oil market.
The numbers tell the story. The North American oil rig count dropped from its peak in early October at 1,609 to 646 for the week-ending May 29, yet productions is headed in the opposite direction — US oil output hit 9.586 million b/d, its highest daily rate since the EIA began weekly production reports in 1983. The EIA recently forecast another million b/d of oil production growth until it peaks in 2020 at 10.603 million b/d.
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While the most fecund basins are still the Permian, Bakken and Eagle Ford, producers have lasered in on the most productive parts of those basins, leading to greater productivity per rig.
In October 2014, the average new-well oil production per rig in the Bakken was 486 b/d, in the Eagle Ford it was 599 b/d, and in the Permian 207 b/d. In the ensuing seven months to June, the same basins saw new well output per rig increase to 631 b/d in the Bakken, 720 b/d in the Eagle Ford, and 296 b/d in the Permian, according to the EIA’s Drilling Productivity Report.
How did the companies do it? The answers differ from company to company and basin to basin, but there were some common themes.
Several companies reported a reduction in spud to well drilling days, allowing the potential for drilling more wells at the same cost, in turn yielding more production. Oxy has seen a 40% decrease in spud to rig release time in the Wolfcamp area of its Permian holdings from 43 days in 2014 to 26 days in March this year with a target of eventually reaching 16 days, according to the company’s Q1 earnings presentation.
To that end, the company is using a process called “mechanical specific energy” which looks at the formations to be drilled and designs “exactly how much we should do,” said soon-to-be Oxy CEO Vicki Hollub in its earnings call, including “how fast we should rotate the bit and how much weight we should put on it by interval.”
This and other measures allowed the company to increase production guidance for 2015 to 9%-13% over 2014’s 591,000 b/d of oil equivalent, the company said, while decreasing costs. Well costs fell 24% from 2014 to the end of May to $8.3 million, with a target of reaching $6.5 million, the company said.
Pioneer Natural Resources is experimenting with efficiencies on several fronts in the Permian. For example, it is modifying the casing design in drilling its core Spraberry/Wolfcamp formation operation. Now in test phase, the technique offers $500,000-$1 million savings per well and shaves off 10-15 days per well, Pioneer officials have said.
Another savings comes from expanded use of dissolvable plugs in the Eagle Ford Shale, the company said. The plugs isolate fracture intervals along horizontal wells, and using them avoids having to drill them out after a well is fractured. The savings is about $300,000 per well and completion time is reduced by three days per well.
Efficiency gains are not only in shale; Canada’s oil sands patch is also making technological strides. MEG Energy has tweaked existing enhanced modification steam and gas push (eMSAGP) technology, which is typically used years after steam assisted gravity drainage (SAGD) is employed, but MEG is using it earlier in the production cycle.
In SAGD wells, steam is used to heat and pressurize the reservoir, and when the steam cools pressure is lost. But with eMSAGP, gas is able to maintain high pressure without the loss due to cooling steam. The steam can then be redeployed to new wells. This has allowed MEG to reduce steam injection to existing wells by 55% and help cut the cost of production.
The efficiency gains, big and small, are why internal rates of return for basins across the shale-scape are over 10% even with WTI at $50/b, according to Platts’ Bentek Energy calculations. WTI settled at $59.13/b Friday.
Those returns are ultimately what matters and keeps tight oil pumping. OPEC’s actions were a wake-up call, but now the tables have turned and, as ConocoPhillips CEO Ryan Lance warned last week, OPEC needs to prepare for even more competition on the “real possibility” the US crude export ban gets lifted. — Benjamin Morse in New York and Starr Spencer in Houston