Crude oil prices have firmed up, setting new four-month highs in the past two weeks. Brent has climbed to $45 per barrel and WTI above $42, although both benchmarks remain range-bound.
The oil market is close to rebalancing, at least in terms of supply and demand flows, and one big factor has been the steep decline in U.S. shale production.
The oil market is close to rebalancing, at least in terms of supply and demand flows, and one big factor has been the steep decline in U.S. shale production. Below $50 per barrel, very few unconventional producers are making money. But the maturing industry is also facing some drilling challenges that could prevent a substantial rebound in production.
Drilling stalled
A June report from Deloitte declared that the U.S. shale boom “peaked without making money for the industry in aggregate.” The firm estimated that the industry collectively posted $300 billion in net negative cash flow over the past decade and a half.
Through the losses, the industry produced extraordinary amounts of oil and gas. But the pandemic-induced market collapse finally killed off the boom. Many market watchers have speculated when and if drilling would return. The recent stabilization of oil prices seemingly offers a new opportunity to drill.
In a prior era, drillers would recapitalize and get back to work. However, there is no sign that this is occurring. The rig count continues to decline, with the Permian accounting for the most recent week’s losses.
Moreover, drilling permits fell to a 10-year monthly low in July, with only 454 granted to companies, according to Rystad Energy. “This signals the continuity of reduced activity levels throughout the remainder of 2020 at the current strip prices. Unless WTI oil prices move towards $50 per barrel in the next few weeks, a rig activity rebound is unlikely before the first half of 2021,” says Artem Abramov, head of Shale Research at Rystad Energy.
With both the rig count and the number of drilling permits plumbing record lows, there is little chance of a rebound in production in the next year or so. Because shale wells suffer from steep decline rates, overall U.S. oil production could continue to erode.
Productivity problems
Meanwhile, the U.S. shale industry has a raft of other problems. While the financial trouble is increasingly well-known, particularly with oil prices stuck below $50 per barrel, drillers face numerous obstacles in the field as well. A recent report from investment bank Raymond James looks at the increasing likelihood that drillers have largely maxed out their productivity gains. In fact, the bank warned a year ago that drillers were approaching their productivity limits; recent data suggest that this trend is bearing out.
For years, shale drillers squeezed more oil and gas out of wells by drilling longer laterals, using more proppant and water, packing wells closer together, and drilling more wells per well pad. This is the “bigger hammer” approach, as Raymond James calls it. Last year, for example, companies increased production on average by increasing the lateral length of their wells.
But on a per-foot basis, productivity only increased by 2 percent in 2019, according to Raymond James. That is down a 4 percent increase in 2018 and a 12 percent increase in 2017. In the Permian, productivity increased by less than 1 percent, while productivity actually decreased in the Eagle Ford.
Part of the reason is that there is a “practical economic limit” to increasing the length of laterals, which Raymond James says is perhaps around 10,000 feet. Anything longer starts to have diminishing or even decreasing returns. In 2018, shale gas giant EQT drilled wells past 18,000 feet and promised to increase that to 20,000 feet. The wells ended up a financial bust, costing hundreds of millions of dollars.
Parent-child well interference also continues to dog drilling operations. Last year, the Wall Street Journal analyzed the production of Encana (now named Ovintiv). Encana’s 33-well cube development – an enormous number of wells drilled from the same pad – was on track to produce about half the amount of oil over a 30-year period compared to what the company had projected two years earlier.
The average volume of proppant (such as frac sand) used per well has also hit a ceiling, and an industry-wide average is down from a peak in 2017.
All of these trends point to a broader problem – the ever-increasing intensification of drilling has reached its logical limit. “The quest to maximize IP30s was futile as the overstimulated reservoir resulted in not only expedited pressure depletion/sink in the target wellbore, but also increased wellbore interference/fracture migration issues in subsequent adjacent wells,” Raymond James said. “To put it simply, an overaggressive completion lowered the longer-term productivity of the current well along with future child wells.”
In other words, using a bigger and bigger hammer is no longer working. Well productivity growth “likely plateaus barring any additional technological advances,” Raymond James said.
Many of these operational challenges are compounded by the fact that core acreage has largely been drilled and used up. “[W]e also anticipate a decline in productivity as tier-one acreage is exhausted and E&Ps move to lower quality acreage,” the bank said.
The limits on productivity gains is very problematic in light of the years of poor financial results. Companies may not be able to “innovate” their way out of the hole they find themselves in.
The oil market is steadily gathering some bullish momentum, but that has a lot to do with the contraction in drilling. By the end of 2020, the U.S. is expected to account for the single largest loss in oil production at 2.2 million barrels per day, compared to 2019.
Speaking of his company’s spending cuts in the Permian, Chevron CFO Pierre Breber told analysts: “The capital will come back when the world needs energy.”
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