In Some Corners Of The American Oil Patch, $50 A Barrel Really Is The New $100
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The frackers have found that America has more oil than ever thought possible, and they’ll need fewer rigs to get it out.
Oil is back at $50 a barrel. Militant attacks in Nigeria have cut that country’s oil output to a 20-year low. China’s output is collapsing. Even OPEC sees the world oil market tipping into undersupply this year. All of a sudden things are looking up for America’s frackers.
A few American companies are feeling good enough about their prospects that they’ve even put drilling rigs back to work. Two weeks in a row the rig count has increased, with three added last week and nine the previous week.
It’s just a start. The U.S. rig count is down 75% since 2014, with companies decommissioning an average of 10 rigs per week. The new activity won’t yet be enough to halt the decline in American oil output; capital spending is lower for the second year in a row, while output has fallen from 9.6 million bpd in early 2015 to about 8.75 million bpd today. The U.S. rig count is down 75% from its 2014 high.
And yet there is some reason to believe that at least in some corners of America $50 might be the new $100. Drilling and fracking costs are down 25% on average. Companies in the best parts of the Permian basin and Oklahoma’s STACK play are generating 40% returns at $50.
Harold Hamm’s Continental Resources hasn’t brought any drilling rigs out of mothballs yet, but Continental has begun to tap its inventory of already drilled but un-fracked wells. In the industry they call these wells DUCs, for Drilled but Un-Completed. Analysts figure there’s 4,000 DUCs across America, with 2,500 of them targeting oil. Rystad Energy figures that in Colorado’s Denver-Julesberg basin, completing DUCs is economic at oil prices as low as $30 a barrel.
At EOG Resources, the DUC economics are good enough that the company should be able to grow its oil output by more than 10% this year while living within its cash flow, according to analysts at Tudor, Pickering & Holt.
Longer term, EOG has something even more exciting up its sleeve. In its latest quarterly report, the company revealed that over the past three years it has been conducting experiments in four pilot projects in its Eagle Ford shale play, where it has separated out natural gas produced alongside oil and reinjected the gas down dedicated well bores in order to add more pressure to the reservoir, thus pushing more oil out. EOG says that where it works best they’ve seen 30-70% more oil production out of each well. According to analyst Housley Carr of RBN Energy, EOG’s technique has low capital intensity, costing just $1 million per well and generating an after-tax rate of return of 50% at $50 oil.
The company cautions that this particular trick will only work on shale that is sandwiched between layers of impermeable rock — so the high-pressure gas can’t escape. Maybe so, but Bob Brackett, analyst with Bernstein Research, sees it as another step in the evolution of enhanced oil recovery, or EOR. For decades big oil companies have figured out novel ways to squeeze more out of conventional fields — whether by injecting gas, or water or steam or even carbon dioxide. So it was only a matter of time before frackers figured out EOR techniques for shale. Writes Brackett: “We believe there are far-reaching implications of a world in which EOR techinques can be economically applied to source rocks which we haven’t fully explored.” The biggest implication: a lot more oil available, and a lot fewer rigs needed to get it out.
The frackers’ first pass through the new generation of shale oil fields has tapped less than 5% of the original oil in place. Compare that with the 60% recovery rate that BP has achieved in Alaska’s Prudhoe Bay after decades of gas reinjection. As BP CEO Bob Dudley said in a speech last year, each 1 percentage point increase in recovery factor in the big fields of the Middle East would equate to about 20 billion barrels of oil. “Or to put that another way — every 1% is like discovering a whole new super-giant field.”
In New Mexico’s San Juan Basin BP is testing an innovation called the multilateral well, in which a single primary well bore goes down then breaks off into four or five horizontal branches, kind of like the roots of a plant.
Parsley Energy is working on something similar in the Permian; it drilled and fracked three wells close to each other but targeting different strata in the layer cake of oil-bearing rock formations — the result was record well performance. CEO Bryan Sheffield said on a conference call that “We think what’s happening is called stress shadowing, where we find the right vertical spacing that allows for stress plane alteration, but not hydraulic communication. […] We are effectively squeezing the sponge and adding complexity to the fracture network by applying pressure from an adjoining formation. All this leads to enhanced returns compared to single-well development.”
There’s even opportunities in the deepwater Gulf of Mexico. Though there’s little incentive for companies to risk $100 million drilling exploratory wells in the Gulf’s Lower Tertiary trend, Anadarko Petroleum says new investments into subsea tiebacks around established platforms in the Gulf of Mexico can compete favorably with any onshore project.
And what it means for the long term is that there’s lots more oil to be produced, at surprisingly low prices, and with less capital intensity. New rigs from the likes of National Oilwell Varco and Helmerich & Payne are so much more efficient that in the future it will only take a few hundred rigs to do the work that used to require thousands. As an executive of a company building advanced rigs tells me, “We’re going to need to melt down 1,000 rigs.”
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