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.
Source: Enverus & Labyrinth Consulting Services, Inc.
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.
Source: Enverus & Labyrinth Consulting Services, Inc.
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).
Source: Enverus & Labyrinth Consulting Services, Inc.
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).
Source: Enverus & Labyrinth Consulting Services, Inc.
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.
Source: Enverus & Labyrinth Consulting Services, Inc.
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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“The oil reserves will last forever” dreamers are everywhere,look at Rumaila oilfield in Iraq has had 17 bbo in reserves for almost 20yrs
Rob,
I have no idea what possible relevance Rumaila has to the Permian shale plays.
All the best,
Art
Great work Art. Bubble point reached or near as gas oil ratios rise. And the gas is worth little or nothing. The majors are a big money long term play. Maybe CO2 unlocks more oil, recovery is less than 10% so there is still a lot more down there and they can afford to wait. I am reminded of heavy oil in the San Joaquin. Probably not in my lifetime. Keep up the education, we all need it.
Thanks for your comments, John.
All the best,
Art
Art, did you make the plots in fig 4 yourself? If so, can you provide the compaarable rate and log rate v cum plots? I find them more informative.
Bob,
I offer consulting services if you need custom products.
https://www.artberman.com/services/energy-consulting/
All the best,
Art
Have a couple comments:
1. Prudhoe bay and Alaskan production would look different with similar regulatory restrictions as the Permian. Much of the decline is due to restrictions on development. There are significant Alaskan volumes trapped behind regulation.
2. Have performed a similar analysis (productivity per lateral foot by year) and I have not seen as much of an EUR/lateral foot reduction as you show here. Consider that production hit an all time high recently with about 60%-70% of the rigs in 2023 versus 2019. The fact that 2023 well results even on your type curves look as good as 2019 prior to Covid is pretty significant testament to the resilience of the play or operators adapting to get oil out. Anyways, hitting all time high production with less rigs running in 2023 runs counter to the prediction that decline is in the immediate windshield. I do think the decline in rigs indicates economics are worse – primarily due to 50% increase in capital costs compared to 2019 coupled with pull back in prices in 2023.
I don’t claim to know when the Permian will go in decline. But I have been surprised at how productive the wells in 2023 have been even after folks have said for several years that inventory quality has reduced. So when does it decline? I don’t know, but shales only like 15 years old. Another 5 years is pretty significant in terms of providing reserves to the world. What happens after that is only anyways guess. I remember talking to a geologist in 2002 as I was going through engineering school and they were telling me the Bakken (my home state basin) was a dried up basin. I also remember listening to speakers at University of Texas when I was in graduate School discuss peak oil and how we were running out of oil.
Point being a couple things. There is some data that run counter to your prediction and very smart people are terrible at predicting things further out then right in front of their face.
Matt,
I didn’t look at lateral feet, just EUR.
I addressed the all-time high production in my post. You should know that there are lags and leads and that high initial rates will boost production in the short term.
I showed data on 2023 production in my post. Current average production rates are lower than 2021 and 2022. It doesn’t seem like you paid close attention to what I wrote and showed.
I’m sure that there is some subset of the Permian that looks strong but that’s not relevant to the macro picture. It’s the future of overall output that matters to markets and prices.
I did a detailed analysis of all wells that I didn’t show in my post. It looked much worse than what I posted which was just on horizontal wells.
All the best,
Art
“…beyond regulation”.
Which are unnecessary? This is a common response when operations become marginal. A push to reduce regulation, cut royalty rates, delay/shirk asset retirement obligations. It’s happening in every field I’ve worked in for the last 40+ years.
https://www.mrt.com/news/article/railroad-commission-orders-no-fly-zone-west-texas-18566412.php
Just saw this article about an underground blowout due to injected waste water. There are more articles having to do with earthquakes caused by injection of waste water throughout the US, leading to a curtailment of drilling.
New Mexico and Louisiana send their waste water to Texas to be injected there on top of the 3.9 billion barrels that are coming out of the Permian. Texas is allowing “produced water” to be dumped into rivers and creeks. Can you imagine what western Texas is going to look like if Permian production continues with wells producing more and more water as they turn over?
Eric,
The situation with water injection is nothing new nor is it getting worse IMO. I doubt that the TCEQ is letting producers dump waste water into rivers and creeks.
I’m not defending the industry, just giving you my opinion.
All the best,
Art
I agree. Both Tx and Okla need more modern haz waste injectors. But another cost of doing business, and I doubt that they will get enough of them.
I’m so glad someone of your caliber has had the temerity to express what no one else dare (apparently) mention, namely that “drill, baby drill” = “drain American energy resources first”. As we export our last dregs of fossil fuels (coal, Nat gas and oil) from the bottom of the oil barrel; and sanctioning Russian oil only accelerates that drainage, and to such an extent it produces the famous Ross Perot sucking sound, only now it resembles the famous scene from Psycho, with the corpse of Janet Leigh representing our economy as its life’s blood is sucked away by madmen who claim they wouldn’t even hurt a fly.
Thank you.
Thanks for the comments, Rob.
All the best,
Art
Skeptics have been fear mongering peak production since the 1970s…yet here we are with record levels of production.
AG,
What I presented was data, not opinion. No fear, just data.
Cling to your fantasies about an unlimited earth but eventually you will have to leave the nursery.
Best,
Art
Hi Art, I just read the article! Very informative and knowledgeable! I do have a question however, where do you see the price of oil going over this decade? Higher or lower?
James,
I’d be glad to have a one-on-one discussion with you on this.
Please contact my business manager to schedule a discussion: [email protected]
All the best,
Art
Art, what do you make of Exxon’s claims/hopes of doubling recovery with new technology?
https://www.reuters.com/business/energy/exxon-ceo-says-5-year-program-could-double-its-shale-output-2023-06-01/
Tom,
Exxon worships at the alter of technology and believes that technology can make even the impossible come true. I don’t.
All the best,
Art
Between parent/child communication, down-spacing, tier 2 development, and the unceasing decline in rig counts, I’d say we’re looking at a serious reduction of supply starting probably second quarter.
For the number of people here questioning the consolidation of Permian producers; the logistics of managing a knee jerk over-drilling reaction to the resulting increases in prices from reduced output will be much more simple and measured. Further, with fewer players D&C prices will be lower.
In the Permian, it will be interesting to see if larger scale development of the Miss/Barnett delays that reduction regionally.
Austin,
The Permian is a field and will behave just like any other field. It will eventually peak and decline. Smart operators will look for ways to improve output and they will be partly successful for awhile.
Earth physics and 150 years of field development does not get a pass because some humans think it’s different this time.
All the best,
Art
The combinations will be purely accretive, in spite of what Exxon wishes. Which is not to say that no value will be added. Improved facilities utilization and run offs ain’t nuthin. FYI, there will be NO deals on service rates from these combinations. A big part of the shale “miracle” was service industry hollow out, and that’s over.
“Further, with fewer players D&C prices will be lower.”
Nope. They’ve been depressed too much, for too long. Fleets are cannibalized and longer wells mean that some rigs are marginal to drill them. Sand, manpower, water, iron. All up and will remain up. Producer combinations will NOT help, via big guy purchasing power.
Supposed to be an entire ‘nother layer below that I’ve heard, just some test wells so far – that true?
Balter,
There’s always something a little deeper that we always knew about, didn’t think much about but now is the greatest thing ever…but we can’t tell you about it yet because it’s so great that we have to keep it a secret.
That’s the oil business.
All the best,
Art
Art,
Excellent and well thought out article. You’ve concisely explained the ultimate parameter of tight plays that was lost/ignored/overlooked in the frenzy to get into the play 15 years or so ago. I especially liked your comment on the “pass on the laws of earth physics”.
Thanks, Larry. Good to hear from you!
All the best,
Art
Nice work. It does seem that there is a collective delusion among many investors and politicians about this reality. Instead of being concerned about this situation I more often encounter people saying that once Biden stops trying to put the oil industry out of business, we will really start pumping.
Justin,
There is a false meme that regulations keep operators from drilling but really it’s capital. The average Permian well costs $9 mm so it takes lots of other people’s money to mount a serious drilling campaign.
No one wants to underwrite drilling so it has to come largely from cash flow.
All the political changes in the world won’t change capital availability.
All the best,
Art
Does the decline in production mean that drilling rates increase, or does the breakeven increase to the point where drilling isn’t justified?
Jason,
I don’t know. It mostly depends on capital available + price.
All the best,
Art
As I’m sure you’re aware Doomberg has recently published a piece arguing the exact opposite. The gist of it was that technological advance offsets poorer geology. I’d be interested in your thoughts and would love a pod between you and the Green Chicken!
Colin,
Doomberg has a faith-based belief in efficiency that simply cannot be supported by data. Efficiency gains over the last decade have averaged about 1%, not the 8-10% that he cites.
I show DATA to support my work. He talks and hides behind a chicken. Take you pick about who you believe and why.
All the best,
Art
So why all the Permian consolidation? The buyers are making a mistake.
Not necessarily, Cliff. As I said in the post, operators are making money.
All the best,
Art
Best concise current US production and long term forecast report I’ve seen in awhile. Very informative and revealing. I question the production numbers out to 2050, as there are too many variables both known and unknown. But, I’m not knowledgeable enough nor informed enough to make a valid objection.
Randall,
Thanks for your comments.
All the best,
Art
Per an earlier comment, improved facilities utilization and run offs. Both needed.
Scott Sheffield got it right. Be best in class at what you do, then sell high when your business model apogee’s. He will live the rest of his life abundantly, and have an engaging hobby job on the Exxon BoD. More power to him…
Thanks for taking the time to reply, Art. I’m puzzled by the Doomberg article – I value and subscribe to Doomberg but this one seemed insubstantial and vague – really just “necessity is the mother of invention”. Is it possible that they know something that we don’t and that they can’t tell us directly? Is the background to the article the technological developments that XOM cited in justifying their recent Permian acquisition? All of your data would be valid but no longer predictive in that case.
Colin,
I see Doomberg as an idiot savant. He’s a guy who worships at the alter of technology and believes that technology can make even the impossible come true. I don’t share your respect for him. I think he’s dangerous.
All the best,
Art
Shale oil could have been a great resource that lasted for decades but it was produced at a loss for most of it lifespan, not only destroying investor’s money but driving oil prices down and suppressing capex around the globe.
Excellent, excellent piece Art! Wish I had it yesterday when I recorded my rebuttal to Doomberg’s “more than enough for long enough” Peak Cheap Oil thesis.
I did still use several of your charts, all this full attribution of course as always…
I’d love to get you back on the show, as this topic of oil is once again moving to front and center (hey, even JPM commodities gets it now).
Chris M.
Thanks, Chris. Doomberg really does seem to have gone off the rails. I’d love to do a show with you–anytime.
All the best,
Art
Hey Art,
I’ve been following you for a long time, appreciate your work and consider myself a student of the energy business. I completely agree with your conclusions and also can’t figure out why Doomberg has adopted their latest Cornucopian view of oil and gas. It seems pretty logical that, yes, we’ve had a tremendous increase in production over the last 15 years due to shale fracking but the empirical evidence seems irrefutable that a peak is imminent. In addition the far side of the peak seems cliff like, not good. My sense is natural gas and associated NGL’S face a similar prospect with an even larger share of domestic production coming from shale formations, thereby an even larger problem. Is Doomberg in the midst of changing their name to Pleasantville??
Keep up the great work. Ted.
Ted,
As I replied to Colin,
“I see Doomberg as an idiot savant. He’s a guy who worships at the alter of technology and believes that technology can make even the impossible come true. I don’t share your respect for him. I think he’s dangerous.”
All the best,
Art
If we take your information and relate that with modern farming practices, shipping, dependence on the internet, national debt levels and the western power grid, it looks like interesting times.
Keith,
These are interesting times. They may get less pleasant.
All the best,
Art
There’s an important piece missing to the article. As anyone knows in the petroleum industry, our refineries were built to process the dirty oil of the middle east and not our own domestic oil. It’s an inverse relationship between where we extract and refine. It won’t do any good to keep our clean oil home if we don’t have the refineries to process it. No one in their right mind would Invest capital into new refineries or changing the ones we have under the current national and state governments energy policies. So the oil & gas companies are going to maximize output and profits while they can. I’m in agreement that at some point there will be consequences down the road.
Mosca,
If you have more money than you need, should you give it away?
All the best,
Art
Thanks Art! What do you think about spare capacity in countries like Iran and Venezuela? Will spare capacity in other countries keep prices within 100$ or is oil destined to go beyond 100$ by 2030?
Arch,
Close to zero.
Best,
Art
If you are right about our Permine Basin blowing down soon and oil production declining very fast in just a few years. Then WHY are the Majors paying Billions for assets that you say will be worth very little in a few years ? You look like an idiot, unless you have a very good excuse ? A lot of knowledgeable people in this field think the opposite!
Max,
A lot of knowledgeable people thought real estate values would increase forever and that securitized mortgages were a good idea in 2008.
A lot of knownegeable people thought shale plays would make money from the outset.
A lot of knowledgeable people thought Gaza was pacified.
So much for knowledgeable people.
I showed a mountain of data to support my views. Show yours. Anecdotes are not data.
All the best,
Art
Hmmm… The region around Venezuela is reported to have huge reserves, so a political change could unleash them in a decade or less. Maybe the higher powers are bettng on that on Arlington?
Regarding S Sheffield, you wrote last year that he was primarily playing his book with his comment. You were also not sharing many of G&R’s views. Has that changed?
Thanks for the fantastic work and ask them best.
Michael,
Venezuela’s “reserves” are not reserves.
A reserve is a volume at a price. What price would justify capex in such a country?
All the best,
Art
” Close to -0-. Are you referring to “spare capacity” ? Or Actual value of the reserve under the ground? I try to understand
as a foreigner.
Jae Park,
Read the comment to which I responded.
“Thanks Art! What do you think about spare capacity in countries like Iran and Venezuela? Will spare capacity in other countries keep prices within 100$ or is oil destined to go beyond 100$ by 2030?”
All the best,
Art
Thank You Art
Your an artist painting an image, I really appreciate the incite..
Thank you, Shane.
The communication of science is a form of art I suppose.
All the best,
Art
Art, your ‘ol friend, Mike Shellman here…this article is a long time coming and absolutely terrific. I applaud you. By year end 2024 the US will have exported 8 G barrels of Permian tight oil to foreign countries, every barrel we are going to wish we had back in the US, for OUR national security someday very soon. Exports need to stop, NOW.
Thank you. My intent is to send this article to any politican I know capable of reading, and caring about our nation’s long term hydrocarbon future; admittedly that’s not very many.
Happy New Year !
Mike Shellman
Good to hear from you Mike and good luck trying to get the attention of politicians!
All the best,
Art
For non-geologists – American shale oil is better to be considered the oil in war-torn Middle East.
The more war-torn Middle East, the more sustainable remains America’s shale oil.
Both entangled telepathically?
It seems so.
This far, USS Gerald Ford & company are making their way this week back to America from the Mediterranean – after checking out that there is no real enemy of magnitude in the Middle East.
USS Eisenhower & company, though, are staying behind in the Persian Gulf – still checking out if there is any remaining oil in Iraq, Saudi Arabia, Kuwait, Iran, UAE, Syria, Sudan, Libya, Algeria.
And it is here where the entanglement is happening – producing 13+ million barrel of shale oil in America requires the US navy to babysit the little remaining oil in the Middle East.
The newest in the US navy, USS Gerald Ford, will likely never depart America again – no enemies of gravity and no more babysitting required.
One of the oldest in the navy, USS Eisenhower (Launched 1975), on the other hand, will likely never return back to America again – but rather will be left retired and recycled overseas – mission well done – the fossil fuels age – is over.
“ No energy store holds enough energy to extract an amount of energy equal to the total energy it stores” (2017).