Surging onshore oil production wrested from wells using unconventional drilling techniques may have reached its maximum level and could decline as producers deal with well interference and “rock quality deterioration.”

Raymond James & Associates Inc. analysts have said previously that they believe the single most important longer-term driver of oil prices and energy markets over the next five years would be changes in U.S. well productivity.

That productivity finally appears to be leveling off. In fact, it may be tracking far below the Raymond James model, an underperformance that could reflect a “significant inflection point in future global oil supply/demand balances,” said the team led by Marshall Adkins.

Over the past seven months, domestic oil supply growth has been tracking below the same period last year, up by less than 100,000 b/d to date from nearly 600,000 b/d over the same period of 2018.

In the past eight years, the Raymond James model typically has predicted high domestic supply growth, while actual production has generally come in even higher than the model, Adkins noted.

However, to date this year, U.S. oil supply growth “has significantly undershot our model,” with overall U.S. oil liquids production slowing since November 2018. Overall well productivity gains are down.

Productivity for every new U.S. oil well drilled, as measured by initial production (IP) over 30 days, has increased, on average, by nearly 30% per year over the past eight years, according to Raymond James research.

The "bigger hammer" approach, defined as using longer laterals with higher proppant loadings and increased fractures, appears to no longer be working as well as it had been.

Improvements in reservoir imaging, wellbore placement and other technological advances have provided an assist, “but most of the U.S. well productivity gains have simply been driven by the ‘more, longer and bigger hammer,’” Adkins said. There is a limit, though, to the big hammer approach.

Through the first six months of this year, domestic well productivity gains “have only amounted to about 2% (versus our 10% growth estimate),” Adkins said. “We believe that this represents clear evidence that U.S. well productivity gains are beginning to reach maximum limits and may even roll over in the coming years as the industry struggles to offset well interference issues and rock quality deterioration.”

The Raymond James team also provided a caveat about last year’s 15% year/year well productivity increases from 11% in 2017. There was a slight uptick last year but it was “largely a one-off gain,” as ExxonMobil and Chevron Corp. each accelerated Permian Basin activity and adopted more efficient drilling techniques.

In a deeper dive of IP rates over 90 days (IP-90), Raymond James determined that not only has productivity growth slowed, it declined in 1Q2019, averaging 2% lower than the 2018 full-year average.

“On a sequential quarterly basis, IP-90s in 1Q2019 were 1% lower than 4Q2018 and 5% below 3Q2018 levels,” Adkins said. “Sure, production rates can vary quarter by quarter depending on the breakdown of wells brought online by basin, but two consecutive quarters of IP-90 declines are hard to ignore.”

More dire still are the IP-90 rates in the Permian, said the analyst team.

“While U.S. IP-90s declined 2%, Permian IP-90s declined 10% relative to 2018,” Adkins said. “On a sequential quarterly basis, IP-90s in 1Q2019 were 6% lower than in 4Q2018 and a whopping 14% lower than 3Q2018.

The Permian has been the fastest growing basin in terms of productivity for several years. Given that the basin has accounted for about half of all Lower 48 activity, “it’s reasonable to assume that U.S. productivity growth will continue to trend in the same direction as the Permian,” Adkins noted. “Should Permian productivity be topping out, the U.S. Lower 48 likely follows.

Similarly Unimpressed

BMO Capital Markets analysts led by Phillip Jungwirth recently updated their analysis of well productivity trends across major Lower 48 unconventional plays and did a deep dive on  individual operator/county levels for 2017-2019.

The initial 2019 data suggests a continuation of 2018 trends, but the lateral-adjusted/well productivity gains are minimal, Jungwirth said.

“In 2018, we estimate the seven shale plays in our study reported 1% year/year lateral adjusted-well productivity improvement,” with the Permian Basin Delaware sub-basin flat and its twin Midland sub-basin up 3%.

In addition to the Permian, BMO’s team reviewed the Eagle Ford and Bakken shales, the Denver-Julesburg (DJ)/Powder River basins (PRB), the Appalachian Basin, along with Oklahoma’s two reservoirs, the South Central Oklahoma Oil Province (SCOOP) and the Sooner Trend of the Anadarko Basin, mostly in Canadian and Kingfisher counties (STACK).

The initial 2019 data for the Delaware indicated 12% year/year gains, while the Midland was 7% higher, “but lease allocation and pending wells can create noise,” Jungwirth noted. The DJ and PRB appeared to have lower year/year well productivity. The SCOOP and STACK also were  bottoming out, and down year/year.

The Eagle Ford, meanwhile, continued to show steady gains, up 8%, while Bakken gains of 5% are “surprising, given poor operational updates from several public companies.”

BMO also quantified the impact from high grading at the county level and estimated zero improvement or degradation last year, with the Eagle Ford the only play that has benefited.

“That said, In 2019, we estimate a 2% high-grading gain, driven by Delaware (3%), Eagle Ford (6%), Appalachian Basin (3%) and SCOOP/STACK (4%).”

Because well productivity doesn’t tell the entire rate of return story, BMO’s analysts also summarized 2019 budgeted capital expenditures (capex) per lateral foot by operator, with spending broken down by category. Analysts divided the lateral footage completed in 2019 by drilling and completion (D&C) plus facilities costs.

The median cost for a natural gas well was $1,040/foot, while DJ wells averaged $660. Permian wells averaged $1,280/foot and were higher in the Delaware than in the Midland. For the Bakken, a well on average cost $1,030/foot. For large-cap diversified producers, wells were on average $1,150/foot. Median all-in capex, as D&C is only 77% of capex, averaged $1,130/foot across the coverage, according to BMO.

‘Extremely Rapid’ Base Decline

Global consultancy IHS Markit’s proprietary data using artificial intelligence also weighed in Tuesday. Researchers assessed, automated and predicted the future well-by-well production for nearly one million producing wells in the North American databases.

Researchers determined there would be an “extremely rapid” base oil decline rate of 35% during the next year for North American onshore wells. The 35% decline compares with base decline rates of 5-14% of most global petroleum systems over the same 12-month period, and a U.S. base decline rate of less than 15% a decade ago.

"The treadmill that producers are fighting is moving very fast," said IHS Markit’s Raoul LeBlanc, vice president of North American unconventional oil and gas. "As producers come under pressure to restrain investment, this decline rate is becoming the main factor that promises to slow the explosive U.S. production growth we’ve witnessed the past few years.”

Comparing 2017 to 2019, the IHS Markit researchers determined that the onshore oil base decline nearly doubled, measured by the production drop from January through December of a given year, without accounting for wells added by new capital.

Base production declined by 1.8 million b/d, or 28%, in 2017, and it is forecast to fall by 3.5 million b/d, or 35%, in 2019.

The analysis also revealed some conclusions about the current unconventional drilling-dominated system, according to IHS Markit. Even with a decline rate of 65-85% in first-year production for most “young” wells, in a “steady state, closed system,” the steep fall off is sustainable because the high initial productivity offsets absolute declines.

In addition, individual U.S. onshore wells drilled today with “few exceptions” appear to follow a similar decline path as wells drilled previously.

“In other words, companies are not ‘pulling wells harder, and much more intensive hydraulic fracturing is not generally leading to faster decline rates,” the researchers said.

Base-decline rates for the North American wells varied directly with the production-weighted age of the well base, i.e. how rapidly production was expanded in the previous one to two years.

“Due to their unique producing portfolios, companies today are in very different positions relative to their current base-decline rates,” LeBlanc said. “The danger of high well production decline rates is two-fold -- namely vulnerability and degradation in production efficiency.

“Vulnerability involves anything leading to materially reduced completion activity, such as a price drop, weather, or a financing crisis. Volatility and quality degradation are the real threats.”