Eagle Ford Shale–A Preview of Permian Decline

Energy Aware II

The Eagle Ford Shale was the hottest play in the United States a little more than a decade ago. In mid-2012, there were twice as many rigs drilling horizontal wells in the Eagle Ford as there were in the Permian basin.

U.S. Shale Plays
Figure 1. Map showing U.S. shale plays. Source: EIA.

Now its decline is probably a preview of what to expect from the Permian basin a few years from now.

The Eagle Ford still produces more than a million barrels of oil (mmb/d) and 5 billion cubic feet of gas per day so that’s the first thing to expect about the future Permian. Plays don’t crash and burn but follow an undulating path downward over years or decades.

Eagle Ford production climbed steeply after 2010 and peaked at 1.6 mmb/d in September 2015 (Figure 2). Much of its decline over the years that followed were because of low oil prices. Although output increased again in 2018 and 2019, it never reached its 2015 level. The Pandemic in early 2020 resulted in a second period of decline and recovery. Production has fallen about 6% since August 2020.

Many people think that advances in technology and ingenuity will somehow reverse the inevitable decline of shale plays like the Eagle Ford. Indeed, those factors have made some difference. The estimated ultimate recovery (EUR) for the average well increased through 2021 despite falling field production levels (Figure 3). That was mostly because operators drilled longer laterals and used more effective fracking methods. The advances were impressive but the technology wasn’t free and well costs increased.

Since then, however, well performance has fallen below levels before 2021. Wells that began production in 2022 will produce about 26% less than 2021 wells and the most recently drilled wells will probably produce more than one-third less oil.

Eagle Ford average 2022 horizontal well EUR declined 119,000 barrels (-26%) since 2021. 2023 EUR declined 158,000 (-35%) since 2021.
Figure 3. Eagle Ford average 2022 horizontal well EUR declined 119,000 barrels (-26%) since 2021. 2023 EUR declined 158,000 (-35%) since 2021. Source: Enverus & Labyrinth Consulting Services, Inc.                                                   

Initial production rates have also declined. Figure 4 shows that 2022 maximum rates (in green) were lower than rates in 2021 (in gold) and that 2023 rates (in red) are lower still.

Over-drilling is probably the main reason for poorer well performance. There are currently almost 25,000 horizontal wells producing in the Eagle Ford play (Figure 5). The green symbols show predominantly oil wells and the red symbols, gas wells. The blue lines show the horizontal well paths.

There are currently almost 25,000 horizontal wells producing in the Eagle Ford play
Figure 5. There are currently almost 25,000 horizontal wells producing in the Eagle Ford play. Source: Enverus & Labyrinth Consulting Services, Inc.        

Figure 6 is a close view of the map from Karnes County, the most oil-productive portion of the play. There are so many wells in Karnes County that its title is obscured in Figure 5 (it is north of Bee and Goliad counties and south of Wilson County on the map).

There are 14 wells per square mile in some areas of the Eagle Ford play (46-acre spacing). Bottom hole locations average about 300 feet apart.

There are 14 wells/sq mi  in some areas of the Eagle Ford (46 acre spacing). Bottom hole locations average about 300 feet apart.
Figure 6. There are 14 wells per square mile in some areas of the Eagle Ford play (46-acre spacing). Bottom hole locations average about 300 feet apart. Source: Enverus & Labyrinth Consulting Services, Inc.        

The problem is that when wells are too closely spaced, their reservoir drainage areas 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. 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.

Earlier this month, I wrote a post titled “Beginning of the End for the Permian” in which I showed the same trends of declining EURs, initial production rates and over-drilling. Many people asked me, “when will the Permian start to decline and what will that look like?”

That’s hard to answer but a few things are clear from comparing the Eagle Ford and Permian plays. Shale wells and fields don’t last forever. They are fields and just like any other fields, they peak and decline. Producers are smart and will find ways to boost well performance until they can’t. Technology can help but it is unlikely to reverse declining output for very long—and it comes at a cost.

In both the Eagle Ford and the Permian, smart operators sacrificed long-term results for short-term gains. They over-drilled the plays despite strong engineering evidence that wells should not be drilled so closely together.

I expect the Permian to roughly retrace the trajectory of the Eagle Ford. It will peak in a few years and then decline in an uneven path that is modulated by oil price and available capital. Like the Eagle Ford, the Permian will continue to be an important source of oil supply many years after it begins to decline. At the same time, relatively small changes in supply often have an outsized effect on world prices.

U.S. shale plays have been the only source of global supply growth for a decade. Markets didn’t react strongly when the Eagle Ford began to decline because Permian supply more than offset the loss. Permian decline will reverberate loudly through global markets when it happens.

Art Berman is anything but your run-of-the-mill energy consultant. With a résumé boasting over 40 years as a petroleum geologist, he’s here to annihilate your preconceived notions and rearm you with unfiltered, data-backed takes on energy and its colossal role in the world's economic pulse. Learn more about Art here.

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22 Comments

  1. Ken Pentel on January 29, 2024 at 10:16 pm

    Thanks Art

  2. GILMER JOHNSON on January 19, 2024 at 3:43 pm

    What about the northern nm oil in Quay county

    • Art Berman on January 20, 2024 at 7:17 pm

      Gilmer,

      What about it? It’s mostly helium. That’s not a great indicator for oil.

      All the best,

      Art

  3. Will Stewart on January 19, 2024 at 12:37 pm

    Thank you for your exceptional far-sighted analysis on what is to come, as the US public seems to have completely forgotten about 1973, 1979-1981, and 2008, reinforcing the observation of the first US Secretary of Energy, James Schlesinger who noted “America has only 2 modes: Complacency and panic.”

    • Art Berman on January 20, 2024 at 7:12 pm

      Thanks, Will.

      All the best,

      Art

  4. Marcelino Chavez on January 18, 2024 at 7:27 pm

    I would just like to know how many times the Permian play has been at its peak. AGAIN. LOL

  5. Conrad Maher on January 18, 2024 at 5:04 pm

    Hi Art,

    Back to reading your posts. It is good to have your take on the production from shale plays (source rock) and other topics. Thank you for your work.

    • Art Berman on January 19, 2024 at 3:55 am

      Thank you, Conrad.

      All the best,

      Art

  6. Jeffrey Brehm on January 18, 2024 at 4:09 pm

    Geos from my (and your) generation are different than those coming up from below. And many of my generation (the 1970-1986 hires) are already riding (or have ridden) off into the sunset. No one was hired from roughly 1986 to 2000. The younger crowd is a mostly shale-driven ethos. And a walk around NAPE shows that the overall geoscience/engineering population has declined. Masochist that I am, I am still at it, but I work with a group whose members are fast approaching ancient status.

    My question is, what comes next? My own alma mater semi-major got spoiled by shale plays (geophysicists? who needs ’em. Petrophysicists? so yesterday. All we need is smart senior management to buy into deals, some drillers and someone to put sticks on a map.) I would think that a revamping of management thinking is in order, and a re-acquisition of technical skills will be needed. But to where? Will companies go back overseas like the 1970s/80s? There are a few new things popping up here and there (Norway, Israel, Guyana, etc), but no concerted stampede movements. The deals with foreign governments aren’t as lucrative as they once were. Or will we be simply going back over old ground here at home? Everyone has the same list of plays, ordered in roughly the same way, and even the shitty ones have been pretty well worked over at this point. That would seem to have limited upside.

    I get the uneasy feeling this will be a problem in a few years as the Permian, which is all the rage at the moment, begins to reach its limits like the Eagle Ford has.

    JB

    • Art Berman on January 19, 2024 at 3:54 am

      Jeffrey,

      What you describe reminds me of what I faced as an area supervisor 40 years ago. Nothing looked very good.

      The industry went through a fundamental paradigm change in the 1980s with risk aversion as its avatar. Now, a day of reckoning is looming on that choice.

      I don’t know the answer to your question but I suspect that the industry’s future is being written by capital markets more than E&P staff.

      All the best,

      Art

  7. George W. Grunau on January 18, 2024 at 3:40 pm

    Art, I always appreciate your data-filled posts. Far too often, we see “experts” pontificating about this or that, with only their hot air as support. I try to read most everything you post and, while I often take issue with your conclusions, I value and respect your opinions and the details from which you draw them.

    That said, I think this post paints an overly pessimistic viewpoint of the rate of decline that can be expected from the Permian basin (PB). The Eagle Ford (EF) reservoir section, as you know is quite thin, generally only a few hundred feet at most. Some notable deviations in this trend occur in the south Texas and east Texas portion of the play, but in the core of the developed play, the EF is fairly thin and, as you state, suffers from overdevelopment. With reservoir thickness as the key, when comparing with the PB, where the total reservoir section is more than 10x that of the EF, I think it’s more reasonable to expect a much lower rate of decline from the PB reservoirs than the EF, purely due to the physical dimension of the reservoir. When combined with future development zones in the PB, I really don’t see the EF as a suitable proxy for how quickly the PB can be expected to decline. In my estimation, its decline will effectively mirror total reservoir thickness.

    Thanks again for the useful no-holds-barred content you provide.

    • George W. Grunau on January 21, 2024 at 11:05 am

      Art, Thanks for the response. My impressions are anything but anecdotal.

      You say you largely rely on DCA, an extrapolation of oil and gas recoveries far into the future, with hundreds of real and theoretical assumptions which can yield errors galore. DCA has its place, but will always be trumped by mother nature – length, height, width, fluid types, p/p of the reservoir, also laden with assumptions. I was simply pointing out that when comparing those things, the Permian Basin and the Eagle Ford are not even in the same league. Sure, both are declining and are finite, but for me, your statement that the Permian will roughly retrace the decline of the Eagle Ford is a statement that is overly pessimistic.

      This said, I appreciate your voice in the mayhem and your desire to bring candor to the conversation. We’ll never get better without dialogue and debate. Kudos Art.

      • Art Berman on January 21, 2024 at 12:42 pm

        George,

        Pessimism and optimism are not science. I rely on patterns and the Eagle Ford and Permian show similar patterns.

        I have been evaluating the Eagle Ford play for more than a decade so my comments and comparisons are not casual.

        All the best,

        Art

  8. Joe Clarkson on January 17, 2024 at 9:50 pm

    Why don’t we hear about more shale plays? I’ve heard of the Vaca Muerta play in Argentina and a little bit about aborted exploration in the UK, but not much else. Are there any more Permians out there?

    • Art Berman on January 18, 2024 at 3:22 am

      Joe,

      We don’t hear more about shale plays because there aren’t very many that are feasible. All the ones with potential are being developed or explored. There may be 3 or 4 outside of North America.

      Not every shale will make a good shale play just like not every human is capable of competing in the Olympics.

      Geology is 80% of the why. The other 20% is political and public opinion.

      All the best,

      Art

      • John DeSalvo on January 18, 2024 at 8:27 pm

        I read a couple years ago Huge reserves discovered in the base of the Rocky Mountains that have been left untapped.
        Why aren’t they being developed?

        • Art Berman on January 19, 2024 at 3:57 am

          John,

          What huge reserves? They were explored in the early 1980s and found to be minimal.

          All the best,

          Art

          • Michael Smith on January 19, 2024 at 5:19 pm

            He might be thinking about kerogen deposits which it is pretty clear by now are a dead end. Sometimes people confuse oil shale with shale oil.



  9. Jim Applegate on January 17, 2024 at 9:46 pm

    Art, I certainly appreciate your articles. Very informative and thought provoking. I am still trying to sell some conventional prospects…with perhaps 10 million bbls of reserves, but it is like pushing rope uphill.

    • Art Berman on January 18, 2024 at 3:24 am

      Jim,

      I understand. 10 mm barrels over a few projects is too small for too little available capital.

      Good luck,

      Art

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