Permian – update through August 2018

This interactive presentation contains the latest oil & gas production data from all 17,650 horizontal wells in the Permian (Texas & New Mexico) that started producing since 2008/2009, through August.

Oil production in the Permian from horizontal wells has continued to rise at an astonishing pace, adding about 1 million bo/d in production capacity in the 12 months through August, to about 2.7 million bo/d (with upward revisions coming).

The main driver behind this growth is the high level of completion activity; so far more than 2,800 horizontal wells have been completed this year, double the level of just 2 years ago, and 40% higher than last year.

As shown by the blue area in August, those wells that started so far this year were already contributing to more than half of the total output in that month.

Well productivity has not changed by much in the past 2 years, as shown in the ‘Well quality’ tab. The wells that started in 2018 are so far tracking a recovery slightly ahead of the average 2016 well, which is on a path to recover about 200 thousand barrels of oil in the first 30 months on production (and hitting that level with a flow rate of ~100 bo/d).

Concho finalized the acquisition of RSP Permian in July, and is now the leading unconventional oil producer in the Permian (see ‘Top operators’), just ahead of Pioneer Natural Resources.

 

The ‘Advanced Insights’ presentation is displayed below:

 

This “Ultimate recovery” overview shows the average production rate for these wells, plotted against their cumulative recovery. Wells are grouped by the quarter in which production started.

The improvements in recovery trajectories over the past 8 years are clearly visible here, driven by major changes in well design (longer laterals, bigger frac jobs). However, since early 2016 these trajectories have not shown further clear gains, even though younger wells are still peaking at a higher rate than before.

Later today we will have a new show at enelyst (live chat combined with images), where we will take a closer look at the Eagle Ford, on which we reported last week. The show will be available here in the enelyst ShaleProfile Briefings channel. If you are not an enelyst member yet, you can sign up for free at enelyst.com.

Early next week I will have a post on all 10 covered states in the US.

If you are considering to subscribe to our data or analytics service, don’t wait too long! Starting from January 1st, we will raise our prices with a few percent. Request a trial or a demo here, or contact us.

Production data is subject to revisions.

Note that a significant portion of production in the Permian comes from vertical wells and/or wells that started production before 2008, which are excluded from these presentations.

For these presentations, I used data gathered from the following sources:

  • Texas RRC. Oil production is estimated for individual wells, based on a number of sources, such as lease & pending production data, well completion & inactivity reports, regular well tests and oil proration data.
  • OCD in New Mexico. Individual well production data is provided.
  • FracFocus.org

====BRIEF MANUAL====

The above presentations have many interactive features:

  • 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 selected items.
  • 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

  • Brendan says:

    I’m looking at the Ultimate Recovery tab and graphing wells by Quarter of first flow.

    It seems like the trajectory of the quarterly vintages really improved starting in 4Q13. That trend of continued sequential improvements seemed to steadily continue until 3Q16.

    However, if I look at each quarterly vintage from 3Q16 to 2Q18, I don’t see much of a change. Does this suggest we have seen a plateauing of Permian well productivity?

    Further, I haven’t seen this data, but anecdotally I’ve heard that lateral lengths and proppant usage continued to increase throughout this time period. So are we actually seeing a deterioration in well productivity inclusive of changes in lateral lengths+proppant?

    Is this a fair way to judge a basin’s productivity?

    Thanks

    1. Enno says:

      Hi Brendan,

      I believe that we are indeed seeing some preliminary signs here that well productivity is plateauing in the Permian. And indeed this is not even normalized for the increases in lateral lengths and proppant loadings that happened during this period.

      We have detailed data on these well design parameters, so if you would like to understand this topic in more detail, I’ll be happy to give you an online demo of our analytics service, for which you can also request a free trial.

  • Brendan says:

    Another question – I know I’ve seen a number of analyses that call into question the unit economics of shale. If we extrapolate the 3Q16-current Permian vintages, it looks like we would be significantly above 400k EUR for oil alone. Unless D&C costs have spiralled out of control, that seems quite workable. Am I missing something?

  • Mike says:

    At the moment un-hedged oil in the Permian (+70%?) is below $40. If we ignore that as being a short term anomaly and use $50 net back after marketing differentials one must deduct 7% severance and ad valorem tax, 25% royalty burdens, $10 per BO incremental lift costs, $3 per BO G&A and $2.00 per BO interest costs and we come up with something in the order of $18-20 per BO take home pay. For many, interest costs per BO are higher than $2. Well costs in the Delaware are $9MM plus and in the Midland $8MM plus. I am privy to numerous $10.5MM AFE’s in the Delaware. 400K BO does NOT work. At current prices 800K BO does not work. Last I heard if you can sell associated gas in the Permian, thru Waha you could get maybe 51 cents per MMBTU. There are numerous analysis floating around, by smart oil people, regarding the (low) percentage of shale oil producers that had FCF in 3Q18, when WTI Cushing averaged nearly $70.

  • Phil S says:

    I’m looking at the cumulative production ranking showing the ranking by well, and selecting individual years of first flow. I know oil prices have fluctuated a lot, but using Mike’s 800K BO as break even, there is not a well 5 years old or older that has paid itself off yet. If you use 400K, there are a few that have made break even, but its a small proportion of the wells. Its a bit scary how many wells cumulative production indicates they are still so far from break even! (it would be great if the well rank numbers were given in the interactive view to help identify how many wells have managed a given cumulative production)

  • Enno says:

    Thanks for commenting Phil.

    > (it would be great if the well rank numbers were given in the interactive view to help identify how many wells have managed a given cumulative production)

    That’s a great suggestion, and something we can easily add to our subscription service.

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