Beginning of the End for the Permian
Permian basin and Eagle Ford oil recoveries have both fallen by 30% and Bakken has declined by almost 20%. Those plays accounted for two-thirds of U.S. output in 2023. That means that U.S. production will decline at some time in the relatively near-future.
But wait—isn’t the U.S. producing a record amount of oil? Yes, U.S. output increased by more than 1 million barrels per day in 2023 to 13.2 mmb/d and about 80% of that increase was from tight oil plays. How can well performance be decreasing while production is increasing?
The answer is that shale wells are producing at higher initial rates but are declining faster than in previous years. Their total recoveries are lower than just a few years ago. The wells are burning out. Oil supply—like life—is a marathon, not a sprint. The plays have been over-drilled and wells are interfering. They are cannibalizing production from each other.
The Permian basin accounted by 46% of U.S. domestic supply in 2023 (Figure 1). Other tight oil plays were responsible for another 22%. Conventional and offshore production accounted for only 32% and has not increased for the last 15 years. That makes it pretty clear that if shale production decreases, U.S production decreases. The conventional base is only about 4 mmb/d so that is the level toward which U.S. output will trend.
The Permian, Eagle Ford and Bakken plays accounted for 93% of tight oil production in 2023 (Figure 2). In this post, I will focus on the Permian basin but well performance in the Bakken and Eagle Ford plays follow a similar pattern of deterioration over the last several years.
There are two important approaches to evaluating well performance. The first a comparative rate vs time plot in which monthly production is normalized by year of first production and plotted on a linear scale. This is a “quick-look” technique. It is useful to compare monthly production rates from different years but should not be used to make assumptions about estimated ultimate recovery (EUR).
Figure 3 shows a comparative rate plot for Permian horizontal wells by year of first production since 2018. There are two important observations from this chart. First, initial production rates for 2022 and 2023 were lower than in 2021 but still higher than in previous years. Second, recent-month production rates for 2022 and 2023 are already lower than for 2023. These are both bad signs for the future of Permian well rates but cannot be used to say much about EUR—how much oil the average new well is likely to produce during its commercial lifetime.
In order to determine EUR, a second technique is needed—creating a type curve. This means plotting the production history for well or a reservoir as the log of rate vs time. The history is then matched graphically and projected to the lease-operating commercial limit of the well or reservoir.
The left-hand graph in Figure 4 shows the type curve for Permian horizontal wells with first production in 2018. Production history is shown in green for oil and in orange for natural gas. The black lines extend the history match according to a formula with the starting rate (qi), the curvature of the matching line (b), and initial decline rate (Di) as independent variables. This method accounts for the time-variable nature of rate vs time that applies to most oil and gas reservoirs.
The right-hand graph in the figure shows the same data but plotted as the log of rate vs the log of time (Fetkovich plot). This provides the interpreter important calibration for the choice of the b-exponent. The level of precision provided by type curves and Fetkovich plots is simply not possible using the quick-look comparative rate approach of Figure 3.
The average horizontal Permian well shown in the figure has an EUR of about 428,000 barrels of oil and 2.2 billion cubic feet of gas. Almost 60% of EUR has already been produced.
The results of decline-curve analysis for Permian horizontal wells since 2018 indicates that average EUR decreased 29% from 2021 to 2022 and 38% from 2021 to 2023 (Figure 5).
Table 1 summarizes the results of the decline-curve analysis by year of first production and estimated break-even oil prices. EUR 10 is the barrels of oil equivalent value that uses a 10:1 conversion of natural gas based on a $75 oil and $3.75 gas price, and a natural gas liquids yield of 150 barrels per million cubic feet of gas. The break-even price assumes an average drilling and completion cost of $9 million based on a cost of $800 per lateral foot for an average 11,000 foot lateral.
The main observation is that 2022 and 2023 EUR is lower than in 2021 by a well-weighted average volume of 35%. There is more uncertainty about 2023 results than for 2022 so it is probably safer to assume that the decrease in EUR is closer to 26% than to 35%. That, nonetheless, is both significant and alarming considering that Permian production accounts for nearly half of U.S. domestic oil supply. Drilling remains profitable at current prices for 2022 EUR levels ($60 break-even price) but not at 2023 levels ($83 break-even price).
The U.S. Energy Information Administration (EIA) expects U.S. oil price to average about $77 per barrel in 2024. At the 2018-2023 weighted average break-even price of about $55 per barrel, it seems likely that development drilling will continue at levels of around 5,000 wells per year. That should result in continued deterioration of well performance because the most probable explanation is that the plays have been over-drilled.
Figure 6 shows that average well spacing in core areas of the Permian plays is about 300 to 400 feet between bottom-hole locations with well paths even closer. Some bottom-hole locations are only 100 feet apart.
The problem is that when wells are too closely spaced, their reservoir drainage radii overlap and wells “cannibalize” each other’s production. Optimum well spacing is a complex reservoir engineering problem and it is simplistic to assume that there is correct distance between well paths. Nor do I wish to imply that operators don’t understand how to optimize production. Nevertheless, a report by SLB in 2017 indicated significant interference when laterals were 660 feet apart. A 2021 study suggested that well spacing should be almost 1600 feet.
Other explanations for decreasing EUR include poorer reservoir quality, less effective completion and fracking practices, and declining reservoir pressure. It is beyond the scope of this post to diagnose the problem except to say drilling wells too close together seems like the most plausible explanation.
Meanwhile the business and finance headline of the Wall Street Journal from the first edition of 2024 was “Shale Is Keeping the World Awash With Oil as Conflicts Abound.”
“Shippers in November moved more oil out of the U.S. than what was produced in Iraq, OPEC’s second-largest member, at a record 4.5 million barrels a day.”
Two-thirds of U.S. production is poised to decline during this decade but the United States exported more than 1.5 billion barrels in 2023. That’s 1.5 times the amount exported from 1920 through 1950 when the U.S. was by far the world’s top oil producer averaging 82% of total world output (Figure 7). That’s because until 1973, there was a proration policy to both limit production and exports in order to maintain spare capacity.
What are we thinking? Figure 7 suggests that the United States is now following a policy to drain America first!
The U.S. Energy Information Administration’s (EIA) latest projection indicates that the United States will produce as much crude oil and condensate in 2050 as it did in 2023. U.S. crude production is expected to average 13.1 mmb/d from 2024 through 2050 (Figure 8). Tight oil will average 9.3 mmb/d.
I have considerable respect for the EIA’s work but its shale projections have consistently puzzled me. It seems that the EIA includes probable and possible reserves as well as technically recoverable resources in its tight oil volumes. It does this without any consideration for its own oil-price projections and implications for commercially producible oil.
This unfortunately encourages the popular belief that shale plays will last forever. The problem is that these plays are just like all others except that they cost a lot more to drill and complete. They are fields. All fields decline.
Permian tight oil reserves are estimated at about 15 billion barrels. That’s similar to the reserves for Prudhoe Bay, North America’s largest field. Production peaked in 1987 at 1.7 mmb/d and has declined to 208,000 b/d in 2023 (Figure 9).
In what parallel universe do shale plays get an EIA pass on the laws of earth physics followed by Prudhoe Bay in order to produce near current levels until the middle of this century?
The signals are flashing yellow if not red about the future of tight oil production. My analysis is not an outlier. In May, Pioneer CEO Scott Sheffield said that Permian output will peak in 5 to 6 years. In November, Continental Resources Chair Harold Hamm suggested that core areas of the Bakken play were reaching their peak, and that deeper “tough rock” objectives would be needed to sustain production. Goehring and Rozencwajg wrote in May that the Permian basin was depleting faster than generally believed and that output might peak in 2023.
This is the beginning of the end for the Permian and other tight oil plays. There are decades of remaining production but at lower rates. The data is clear. Wells are producing less than in previous years. It doesn’t take a degree in petroleum geology or engineering to understand what that means. The production peak may come in 2024 or several years later. The details do not interest me.
A long-term decline in shale play oil production that accounts for almost 70% of U.S. supply requires our attention. It may be a good thing for the environment and climate change but it will also accelerate the trauma of a society which is unprepared to live with less.
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