US Shale Oil Production Laid Bare

Enno Peters maintains a web site called Visualizing US Shale Oil Production. This is a wonderful resource for all those interested to understand the history and dynamic of US shale oil. This post is in two parts. It begins with a series of screen captures of Enno’s charts displaying production from the whole USA, the Permian, Eagle Ford, N Dakota (Bakken), Montana and Marcellus plays. Enno’s charts are interactive and readers are encouraged to visit his site to play.

Enno kindly sent me the data that underlies the charts and the second part of this post are a series of my own charts that interogates production, well numbers and decline rates. The legacy production, i.e. the underlying production without new additions, is declining at a rate of 38% per annum.

Let me begin with a brief clarification of nomenclature. Shale is a fine grained sedimentary rock made mainly of clay minerals. Most US shale oil in fact occurs in a wide range of lithologies including siltstones and carbonate rocks. This led to the re-naming of light tight oil (LTO) the tight referring to the low permeability that is characteristic of all such plays. But in this post I will simply use the popular term shale oil when referring to LTO.

I last visited the US shale oil statistics a year ago in: US Shale Oil: drilling productivity and decline rates

And so to the screen captures from Enno’s web site:

Figure 1 US shale oil production from North Dakota, Montana, Colorado, Texas, New Mexico and Pennsylvania estimated to represent over 90% of the US total. Each band represents wells brought on stream in individual years beginning in 2003. The curvature reflects the high decline rates. Production continued to rise to a peak of over 4 million barrels per day (Mbpd) in March 2015 for so long as production from new wells exceeded the decline in the underlying stack (Figure 12). In April 2015, 842 new wells were added and this was insufficient to cancel declines and production has been falling ever since (see below). Note that all pre-2010 production is contained in the narrow band at the bottom of the stack.

Figure 2 The Permian play does not produce glamorous initial production but has much lower decline rate making it the most popular and profitable play for companies to pursue in the downturn. At just below 1 Mbpd it is the third most prolific but perhaps the most resilient shale play in the USA.

Figure 3 The Eagle Ford provides the highest initial flow rates but also the highest declines. The former had made it a magnet for drilling, but now abandoned, production is in free fall. It remains the most prolific US shale oil play, but not for long as gravity is catching up.

Figure 4 North Dakota means the Bakken play. This is intermediate to the Permian and Eagle Ford. Decline has most definitely set in and is increasing.

Figure 5 Montana is also producing from the Bakken, but at 60,000 bpd it is a small bit player.

Figure 6 The Marcellus shale in Pennsylvania is a major shale gas play in the USA producing a small amount of associated liquids. At 14,000 bpd it is a teeny weeny bit player. But resilient. [note added 27th August: Ken Gregory in comments observes that this chart is actually for gas production from the Marcellus in MMcf/d and not for oil production at all. Please ignore the caption to Figure 6 🙁 ]

Part 2….

Figure 7 This chart mirrors Figure 1 up top showing total monthly US shale oil production. The steady rise since 2011 was eventually arrested by the oil price and drilling crash that began late 2014 with peak production just over 4 Mbpd in March 2015. The rig count peaked in October 2014 (Figure 9) and new well additions peaked in December 2014 (Figure 8). Therefore, it did not take long for the drilling slow down to show up in the production statistics. But the decline has been more gradual than many may have anticipated.

Figure 8 The number of new wells added per month peaked at 1113 in December 2014. Decline set in by April 2015 when 842 new wells were added. A year earlier, 800 wells / month was sufficient to maintain production growth the reason being that a year earlier production was about 1 Mbpd lower and absolute decline correspondingly less.

Figure 9 A major fly in the ointment for shale data interpretation is the loose correlation between rig count, drilling and the number of wells that are brought on line in any month. Compare figures 8 and 9. In general, shale wells have been drilled much faster than they have been fracked, completed and brought on line leading to a large backlog of drilled but uncompleted wells estimated at around 3,900 by Rystad Energy in May 2016. It is the rate of fracking and completions that determines new well additions, not drilling, for so long as the rig fleet is able to drill a surplus of wells.

Figure 10 The new production from new wells each month closely follows the pattern of new well additions (Figure 8). Note that first month production on average reflects only half a month and actual first month flows will be double that shown here.

Figure 11 The change in underlying production is deduced by deducting the new wells’ production from the total. Shale plays are characterised by high natural decline rates. Hence if one does nothing, production plummets. The system only survives by drilling lots and lots of new wells all the time. For so long as production from new wells exceeds the underlying production decline then total production will grow. Comparing this chart with Figure 10 you will see that the oil price and drilling crash has reduced the amount of new oil to below the level of decline replenishment as shown in Figure 12. 

Figure 12 Deducting monthly underlying decline (Figure 11) from monthly new oil addition (Figure 10) provides this picture that shows how net additions transitioned to net subtractions. Net subtractions are running at about 50,000 bpd per month.

Figure 13 Converting the legacy decline (Figure 11) to a % of the total produces this picture of % decline rate per month. Multiplying the monthly figure by 12 provides an approximation of annual US shale underlying decline of about 38%. The chart shows that if anything, underlying decline is increasing with time.

Data sources

DMR of North Dakota
Colorado OGCC
Texas RRC
OCD in New Mexico
BOGC of Montana
DEP of Pennsylvania


At the review stage (this morning) Enno pointed out that first calendar month production reflects on average just one half month since well additions will be spread across the month. This placed a question mark on some of my interpretations which were removed from the post at the last minute. This phenomenon is reflected in the data shown in Figure 10 and perhaps also 11 and 12.

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27 Responses to US Shale Oil Production Laid Bare

  1. Euan Mearns says:

    Note that I had hoped to deduce how many new wells / month, and hence rig count, would be required to halt production decline. The information late in the day that first month production may be only half actual flow rate torpedoed those efforts.

    By email Art Berman said that one rig can drill about one well per month. While Enno estimates about 1.5 wells / rig / month.

    Based on the data presented, readers are invited to estimate where the drilling / decline equilibrium should be. I think my figure 12 is wrong since additions are for 2 weeks and decline covers 1 month.

    • Willem Post says:


      Each screen capture only displays a question mark. This is an unusual occurrence. Is there some software issue? Do others have the same?

      • Euan Mearns says:

        The images are displaying OK for me. There is nothing unusual about the screen caps which are standard <200kb png files. I am using Safari as default browser but just checked on Firefox which is also working fine.

      • gmlindsay says:

        No such problems, Willem. I’m using Firefox

      • Willem Post says:


        It looks like issue resolved itself.

        Thank for the article, which in pictures provides quite a revelation.

        At what rate do new holes need to be drilled to achieve a given steady level of production?

  2. Euan Mearns says:

    Here’s one chart I deleted. If we assume first month production is just 50% then new wells are adding 500 bpd. Figure 11 suggests underlying decline is about 150,000 bpd suggesting we need 300 new wells / month to halt decline and that’s where we are at present. Something doesn’t seem to be quite right?

    • gweberbv says:

      Your underlying decline was produced by subtracting the production of new wells from total production, right? So, if you did underestimate the yield of the new wells by a factor 2 this should have an effect on decline, right? Your decline will get bigger.

    • Enno says:


      Thanks for the article. I’m very happy to see that my site is being put to good use.

      Last month, I created a post that focused on how I expect that the total US shale production will decline in the coming years, see:

      You can see there that I expect there that the annual decline rate from end of 2015 (3.7m bo/d) to end of 2016 (almost 2.0 m bo/d) is in the order of 46%.

      The actual decline rate in the year before was 49% (3.9 m bo/d at the end of 2014, vs 2.0 m bo/d at the end of 2015).

      If you click in that presentation on the 2nd graph, you’ll see in the bottom (cumulative chart) that wells in the last couple of years, in the oil basins, are roughly expected to do around 200k bo, by the end of their life (assuming no refracking, and that wells are plugged at the economic limit).
      So if with each well, we’ll get 200k bo, that means that in the long run, to sustain 4m bo/d, we need 20 new wells per day, or just over 600 per month.

  3. Rob says:

    Euan what sort of recover rates does shale gas extraction achieve I was told it could be as high as 40% or as low as 10%

    The UK uses about 3 trillion cubic feet per year

    Bowland Shale gas approx. 1300 tcf according to British Geological Survey.

    Would you like to make a guess of how much recoverable gas the UK is likely to have

    • Euan Mearns says:

      Rob, I’m afraid I haven’t a clue but instinctively feel the answer would be closer to 10% than 40%. This is perhaps one for Art Berman to answer.

    • ristvan says:

      Per OGJ, shale oil recovery factors are running about 1.5 percent with the expectation to reach maybe 3 percent (closer well spacing, more proppant, more fracks/mile of lateral with plug and perf instead of older sleeve method). Marcellus shale gas recovery factors in Pennsylvania are running 12-15% at present. Of course, these are all estimates based on actual decline curves. Bakken oil is about 85% after 3 years. Eagle Ford is about 75%. Don’t recall Permian average, as each of the three main strata is different, and one isnt even a shale.

  4. confused mike says:

    The (apparently) asymptotic shale oil curves are fascinating – As I understand it as a well ages the decline rate slows – the pressure in the well drops slowing delivery of the oil and the year on year delta is smaller.
    If this is correct (?) as less and less wells are drilled to completion ( for instance in reaction to lower oil prices) shouldn’t the underlying decline (the 3.2% per month derived in figure 13) get smaller as the average age of all the wells in operation gets older?
    Am I missing something?

  5. Euan: Figures 11, 12 and 13 indicate that the production decline rate has flattened out – maybe even decreased slightly – since the collapse in the rig count at the beginning of 2015. Any thoughts as to why?

    • E.J. Mohr says:

      Roger, as far as I know, this is because of the newer method of PAD drilling where one pad can be used for multiple completions. This means one rig is far more efficient than in the past, and in addition to this the newer methods involve longer laterals and more frac’s per lateral. And, if that were not enough, many of the shale plays have multiple horizons of pay, and laterals are introduced into every pay zone, and fracked. Here in Canada in the Montney some areas have 8 pay zones, and possibly more. The result is that the top wells are blasting out initial production in excess of 10 million cubic feet of gas per day.

  6. john eardley says:

    Figure 1 shows an annual decline of 2mbpd or 6% per month. I calculate you would need some 450 rigs drilling 1 well per month and producing an initial 500bpd to replace this loss and maintain overall production.

  7. louploup2 says:

    Thanks for the very informative post. Have you tried to correct Fig. 12 by adjusting the period disjunct?

  8. unless I’m missing something, the correct annual decline rate assuming 3.2% monthly decline is 32,313 %

  9. Euan Mearns says:

    I’ve been reflecting on the conundrum of how to calculate the number of new wells required to cancel declines. I’ve reached the tentative conclusion that the way I did this originally, but deleted from the post, may be correct.

    The fact that new wells don’t produce for a full month in the first month is irrelevant to the calculation. What they add to production on average is what gets added and forms the basis for the decline calculation.

    Figure 11 shows monthly decline running at around 150,000 bbls per month. The chart I posted in comments show that new wells add about 250 bpd in the first month. Hence 150,000 / 250 = 600 new wells required to cancel decline. With one well drilled per rig per month we need a rig count of 600 ±. Decline set in at 750 rigs. We need fewer rigs now since production is lower and well performance is improving. DUCs remain a wild card.

    • Willem Post says:


      If 600 new wells/d to halt production decline, how much square miles is that per day?

      The areas of the gas reserves would be used up at that rate.

      How many decades would that last, if all areas of the reserves are not available?

  10. Jan Ebenholtz says:

    Sorry to disturb but what is the point you wish to make?
    Best regards
    Jan Ebenholtz

  11. louisc says:

    How far apart do wells need to be drilled from other ?
    Does each well represent the center point of a radius or does the actual new fracturing occur at the same initial drill point but at different depths ?

  12. Ken Gregory says:

    The caption to Figure 6 for the Marcellus shale gas is incorrect. It says “The Marcellus shale in Pennsylvania is a major shale gas play in the USA producing a small amount of associated liquids. At 14,000 bpd it is a teeny weeny bit player. But resilient.” The graph shows it is producing 14,000 mmcf/d, not 14,000 bpd. Gas production at 14 bcf/d is not “teeny weeny”. Using an conversion of 6 mcf/bbl, 14 bcf/d is equal to 2300K bopd.

    • Euan Mearns says:

      Ken, checking back to the source “Visualizing US Shale Oil Production” I do indeed find you are correct. This chart is for gas and not liquids production. Just one of too many errors in this post 🙁 A consequence of trying to cover too much ground, especially when trying to take some time off. But I’d note that both Enno and Art Berman reviewed this and neither picked this up. But the responsibility is mine 🙁 I’ll add a correction to the post.

  13. Stuart H says:

    It seems logical that any well will produce less as it ages. However, are the declines in production being discussed due entirely to lower capabilities of the wells or some other factor such as price? I can envision a scenario where during a down market (glut) some wells are shut off and waiting for prices to recover. After all the well is there and the oil isn’t going anywhere, or am I missing something?

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