Eagle Ford - update through August 2017

This interactive presentation contains the latest oil & gas production data from 19565 horizontal wells in the Eagle Ford region (TRRC districts 1-4), that started producing since 2010, through August 2017.

In the past month I’ve made again several major improvements to my Texas data:

  • Pending production. Recent production reports have been reported by operators to the Texas RRC, but are not yet processed, and therefore excluded from the published production for the related leases. This is a significant cause for the production revisions that we’ve seen in Texas. I now have access to these pending reports, and that has several benefits: it allows me to report also the last published month of production data (so August, instead of July), it should make the data far more complete (as revisions will be smaller), and this production is reported on well-level, which allows me to use it to improve the results of the lease allocation algorithm.
  • Permit data. Permit data is now also included, and this has helped in getting a more complete picture of the status of wells before they are put on production. Therefore, the “Well status” overview shows a more accurate overview of the wells that have been spud or are in the DUC inventory. Note that this type of data for the last few months is still quite incomplete, due to the delays in processing this information by the RRC.
  • Well tests. There are several states where production is reported by lease, and not by well (e.g. Texas & Louisiana). I rely on regular well test data (in addition to other sources) in order to estimate the production of individual wells on a particular lease. In Texas however, well tests are often significantly overstated by operators, as they are also used to set production limitations by the RRC (“oil proration schedule”). I have analyzed by how much, and in which cases, these tests are overstated, and am using these results to further improve the allocation algorithm. A big ‘Thank You’ to Mike Shellman, who has helped me to understand this topic in detail!

Looking at the above graph, we can see a significant drop in oil production in August, due to impact of the hurricane Harvey. This can also be seen in the “Well status” tab, which shows the number of completions per month: June saw the highest number since almost 2 years (172), but in August this was down significantly (63, still subject to revisions).

If you only select the well statuses “1. Spud” and “2. DUC” in that overview, you can see how this drilling inventory has roughly halved in the Eagle Ford since the end of 2014. Data since May is incomplete. The bottom graph shows that about half of these horizontal wells are now producing at a rate below 25 bo/d.

The ‘Advanced Insights’ presentation is displayed below:

 

 

In this “Ultimate Recovery” overview the relationship between production rates, and cumulative production is revealed. Longer laterals and larger proppant volumes have increased the initial production rates in recent years, but their impact on the ensuing decline seems limited.

If you only select EOG, which is by far the largest oil producer in this region, in this overview (1. use the “Operator (current)” selection, 2. click “All” to deselect all operators, 3. select EOG, 4. press “Apply”, 5. click anywhere on the chart), then you’ll see that its wells are performing better than average, but it also shows limited improvements in recent years.

Another way this can be see is in the 5th tab (“Productivity over time”). Here the performance of all wells is shown, as measured by the cumulative oil production in the first 24 months. Since early 2014, this metric is no longer growing.

Early next week I will have a post on the Permian, followed by one on all 10 covered states in the US in the 2nd half.

Production data is subject to revisions, especially for the last few months. For this presentation, I used data gathered from the following sources:

  • Texas RRC. Production data is provided on lease level. Individual well production data is estimated from a range of data sources, including regular well tests, and pending data reports.
  • FracFocus.org

====BRIEF MANUAL====

The above presentations have many interactive features:

  • You can click through the blocks on the top to see the slides.
  • Each slide has filters that can be set, e.g. to select individual or groups of operators. You can first click “all” to deselect all items. You have to click the “apply” button at the bottom to enforce the changes. After that, click anywhere on the presentation.
  • Tooltips are shown by just hovering the mouse over parts of the presentation.
  • You can move the map around, and zoom in/out.
  • By clicking on the legend you can highlight the related data.
  • Note that filters have to be set for each tab separately.
  • The operator who currently owns the well is designated by “operator (current)”. The operator who operated a well in a past month is designated by “operator (actual)”. This distinction is useful when the ownership of a well changed over time.
  • If you have any questions on how to use the interactivity, or how to analyze specific questions, please don’t hesitate to ask.

Discussion

  • Mike Shellman says:

    Enno, thanks for the heads up but its all your doing, man. You are a genius with this stuff.

    For a long time people needing desperately to ‘analyze’ unconventional production trends in Texas have complained about such things as: Texas operators don’t file production data on time, or the reporting is incomplete, or it is hidden somehow by confidentiality provisions (no such thing in Texas), or the Texas Railroad Commission is not as good as the NDIC, or the EIA has better ‘estimates’ than the TRC. No operator I know reports production to the EIA and there is no such thing as production ‘estimates’ in Texas. Every bbl. and every mcf represents a dollar value and the second that bbl. or mcf crosses the cattleguard in Texas, it better be accounted for. The answer was always in that production classified as pending, under drilling permit numbers, and not finalized, processed production reported under lease ID numbers. Nobody wanted to do the work; you did and I compliment you on it. As I do your work on W-10 well tests and how, why and when they are often over exaggerated.

    It is thru your work, thru realized production data, not amped up IP’s and/or IP180’s, or hyped EUR’s, that people can begin to see the truth about unconventional shale production in America and that there has seldom been much “truth in advertising.” I am grateful for that, as should all Americans be grateful.

    Mike

    1. Enno says:

      I appreciate it Mike! Without your great support my coverage of production in Texas could not have been done as detailed and complete.

  • alex says:

    Question on Eagle Ford. Can anyone who know the data better than me comment on the remaining “sweet spots” in Eagle Ford. It seems as though much of wells are concentrated in a few counties / regions…

    Thanks

  • John says:

    Enno,

    Let me second Mike’s endorsement of you and your work! I doubt that you will ever get the recognition and acclaim that you so richly deserve for so generously making so much of your work available to someone like me. I truly hope that the industry fully embraces your subscription site and your reap the fruits of your labor.

    Mike, my thanks to you as well for your assistance to Enno. I hope both of you receive the recognition you deserve.

    Best to you both!

    1. Enno says:

      That’s very nice of you John, thank you! I hope that you keep finding value in these posts.

    2. Mike Shellman says:

      John, thank you very much but its all Enno Peters. I simply want the shale industry to quit lying to the American public about its future sustainability. Its overall financial condition is abysmal and, in spite of all the hubbub Mother Nature, I believe, is finally having Her way, as She always does, and is closing in on the shale industry.*

      There is a guy on LinkedIn, if you can stand LinkedIn for a moment, named Scott Lapierre, an old Pioneer RE, who is doing some good work on unconventional OOIP and recovery rates (Bubble Point Death), a theory he has on “oil expansion” drive, as opposed to gas expansion. It is very enlightening.

      * Alex, there are a number of good articles of late regarding declining ‘sweet spots,’ well densities and well interference, declining productivity per rig, etc. in all of America’s shale basins. Those articles suggest mother nature is indeed closing in on the shale industry. That industry boasts about ‘drillable’ locations but we have no idea how many of these locations are what is referred to as Tier II locations, away from sweet spots, where development costs will likely be higher (even more infrastructure requirements, bigger frac’s, etc.), UR’s will be much lower and profitability even more difficult to achieve. OPEC, interestingly, recently implied that perhaps US shale oil may not be too much of a future threat to it’s world market share as sweet spots are drilled up. America needs America’s shale oil and shale gas but somebody needs to figure out how private enterprise can make its extraction profitable, so it can begin to pay back its student loans.

      Mike

      1. nuassembly says:

        Mike,

        Once again, like all the audience, my salute to Enno and volunteers like you!
        I read Scott’s new “oil expansion” model for shale oil production and I completely agree that the EURs are completely overly optimistic for shale oil. What’s making things worse are also missing from Scott’s “oil expansion” — for tight oil, there is this extra capillary effect that will pull liquid inside the nano pores, and at the same time water could easily seal the pore throat through capillary effect, all these will significantly increase GOR.

        I share similar conservative views about new energies, e.g. solar and wind or electrical cars, like Mike toward shale oil and gas. Till now, solar’s exponential growth has always been fueled by government subsidies and wall-street lavish investment, and not by final economics. But, there is now a reasonable chance such government and wall-street driven solar power is gaining enough momentum that it will reduce its cost day by day through technology or purely scale, and in the foreseeable future take a reasonable share of the energy pie (now it is still 1%).

        Similarly, shale gas has definitely entered the stage of no-return. Or if shale gas collapses, even Quatar or Russia’s LNG will not make it. The recovery factor for shale gas could easily reach 20% or more than 40% by theory under current technologies, not like shale oil’s <5% even for the best reservoirs under the technologies we have now.

        1. Mike Shellman says:

          I am not an engineer, Nuassembly, but I agree that there are number of mitigating circumstances that will change the way shale oil well performance can accurately be predicted over time, all of which will lead to, as you say, UR’s being significantly less than EUR’s. You’ve named a good reason; wettability ‘phases’ most certainly change over the depletion cycle. I am also interested how nano pore throats restrict, or close with declining ‘reservoir’ pressure and the role that induced fracture closure might occur due to a combination of declining pressure and, for instance, proppant embedment.

          I coined a phrase early in my exploration career that suggests that ‘anticipation is always better than realization.’ The time after a well is drilled and before it is actually completed it a period of lofty hope and grandiose plans. Once the well is completed things are often much different (less) than hoped. Thus the miracle of shale oil DUC’s. Drill a DUC, use any number of type curves for wells within the SEC proximity limit rules and bingo…book 1MMBOE EUR for 40% of the cost. Its perfect. You can puff up like a rooster about reserve growth, save money, meet loan covenants and…borrow some more money. The SEC allows 5 years to complete the well and move it over to PDP. When the buggar is completed, or four years later, after its pooping out and looking like only half they EUR is actually going to be achieved, chances are very high you’ll have to take an impairment on those lofty reserves anyway. So, let the DUC sit and go get another. A crafty bunch, these shale guys.

          I too hope for major changes in alternative energy affordability in the future. We are going to need it all before its over.

          Mike

Leave a Reply

Your email address will not be published. Required fields are marked *