The collapse of oil prices has forced the U.S. shale industry to slash production costs. In order to improve the “breakeven” costs for the average shale well, the industry has deployed three general strategies: improving techniques and technology, such as drilling longer laterals or using more frac sand; focusing drilling on the sweet spots; and demanding lower prices from oilfield service companies. All three of those strategies led to a decline in the breakeven price for a shale wells.
But while the industry plays up the efficiency gains, highlighting enhanced technology and better management, merely focusing on the sweet spots has been “nearly twice as important as better technology in reducing well costs,” as The Post Carbon Institute (PCI) notes in a report published on Monday, “2016 Tight Oil Reality Check.” This is a process known as “high-grading.” In fact, the so-called efficiency gains over the past two years are a lot less impressive once you dig into the causes.
Speaking at the National Oil-equipment Manufacturers and Delegates Society (NOMADS) in Houston a few months ago, IHS Markit’s associate direct for Plays and Basins, Reed Olmstead, poked holes in the notion that the industry has dramatically upended the cost of shale production. He broke down the cost reductions into a few categories: “One of these factors is high-grading, where operators are drilling only the better acreage,” said Olmstead. “This item accounted for about 35% of the break-even price reduction.” Arm-twisting oilfield service companies accounted for another 40% of the lower break-even price. Meanwhile, operational efficiencies – the things that would ensure cost reductions are sustained over time – only accounted for 20 percent of the savings, while learning in the field made up an additional 6 percent of the cost reductions.
In other words, about three-quarters of the cost reductions have come from trends that will not ultimately improve the overall recovery of oil. First of all, oilfield service companies will start demanding higher prices as drilling rebounds, which will lead to a rebound in drilling costs.
But more importantly, even the much-ballyhooed advancements in technology and drilling techniques are a mirage, at least when it comes to the overall recovery of oil from a shale basin, PCI argues in its report. Indeed, shale companies have come up with innovative ways to make shale wells more productive, but while drilling longer laterals and improving the recovery of the average well is great for an individual company, it doesn’t necessarily mean that more oil will ultimately be recovered from the entire basin.
“Longer horizontal laterals with higher volume treatments drain more area and reduce the ultimate number of wells that can be drilled without interference,”the report concludes. Sucking more oil out of an average well will simply frontload recovery – instead of the same oil being recovered from more wells over time, it is being recovered much more quickly from fewer wells. The same is true for high-grading – drilling the best spots today makes it appear as if the basin is getting more productive, leaving the markets with the impression that the shale play can produce indefinitely. But maybe we are just burning through finite reserves at an accelerated rate.
Even if production is to continue to rise, it will require steadily higher crude oil prices. Not only will the underlying resources deplete faster from accelerating recovery, but producing the best oil during times of low prices means that “progressively higher prices will be needed, along with much higher drilling rates, to access poorer quality portions of shale plays and maintain production.” We are producing cheap oil today, leaving costly oil for tomorrow.
The implications of these findings are multiple. First, the rebound in shale production from higher prices might not be as impressive as organizations like the EIA expect. The sweetest of sweet spots are already produced or are currently being drilled, leaving less desirable locations left for when prices rise. More importantly, shale production will not grow indefinitely as the EIA and many other analysts predict. The EIA expects shale output to grow for decades to come, hitting 11.3 million barrels per day in 2040, up from roughly 8.6 mb/d today. And that is the EIA’s Reference Case, not even its more optimistic take on what might happen.
PCI sees these projections as fanciful. For example, the Bakken would need to double production to more than 2 mb/d, a scenario that “lacks credibility,” PCI says. The scale of drilling required is not realistic, and even today, “well interference is already evident in the former top producing county, Mountrail, indicating that available locations are running out,” the report finds. The Bakken would need to see at least double the current maximum of 2,000 new wells drilled per year, which is not only an unlikely development, but would lead to even worse problems of well interference, negating some of the gains that could be achieved from additional wells.
PCI says that the EIA’s “optimism bias” for production is extremely high for not just the Bakken, but also the Niobrara and even for a few of the highly-touted formations in the Permian Basin, such as the Wolfcamp. The EIA is overestimating what can be recovered from nearly all the major shale basins in the country, PCI argues.
Overall, the notion that shale production can continue to rise for another 25 years is doubtful. And given that policy decision are being made on such assumptions – the incoming Trump administration is under the impression that it can drill its way to “energy independence” – the errors at the EIA could have serious implications for the U.S.
Teaser photo credit: CC BY-SA 3.0