Projecting US shale oil production (after June 2016)


In July 2016 I published a post (which you can find  here) in which I showed how much existing horizontal wells were going to produce in the future, if we would assume that their decline behavior would be similar to those of earlier wells.

This post aims to achieve exactly the same goal, and uses the same method and presentation. The main difference is that I now can include wells that started before July 2016, instead of before Jan 2016, and that some improvements were made to the presentation.

The first part of this post will provide a brief description of the results, and how to view them. Later, a more in-depth explanation is given that describes the method used, the differences with the previous result, and other remarks.

Short Story

The results in this post should provide answers to the following questions:

  • How much oil production can we expect from existing horizontal wells over the coming years?
  • How will existing wells decline over time, and how much oil will they each recover?
  • How much oil have operators already produced from their existing wells, and how much is left? With which speed is all this oil recovered in each of the basins?

To be sure, these results do not include any new production after June 2016, and therefore do not provide a full picture of total future production from horizontal wells. As usual, I haven’t included any vertical wells.

For each of these three questions, a matching overview is available in the above interactive presentation.

Let’s go over these views one by one.

“Projected Production”.

Here we can see the historical, and projected oil production from 56,641 horizontal wells that started production before July 2016 in the following states: Montana (since 2003), North Dakota (since 2005), Colorado, Wyoming, New Mexico, Texas and Wyoming (all since 2010).

The view is split between June & July 2016, which is from where the projected production starts.

“Production Profiles”

The average production rates, and cumulative production, for all these wells can be seen in the 2 graphs shown here. If you wish to see only historical, or projected production, you can use the “Show production” selection at the top. Historical production is marked with dots on the curves.

It’s easy to see here that wells from the earlier years (<2010) display a slower decline than later wells, on average. These were wells in the Bakken region in Montana & North Dakota.

If you click on a year in the legend, the related wells will be highlighted. You may then see some overlap of the historical and projected production rate profiles; this is because wells are grouped by the year in which they started. A well that started earlier in a particular year will have more months of actual production data than wells that started production later in the same year, and therefore the projected output of this earlier well will start later.

For the top chart, three ways to scale the axes are available. I have found that for different purposes, they all have their uses. The “Log-Log” setting will show a remarkable convergence of production rates, especially if you have selected “Historical” production only.

“Estimated Ultimate Recovery”

Here I wanted to share some insights into the total historical & projected oil production from all these wells. Both charts here use the production profiles, as seen in the previous overview.

The top chart shows the (gross) total oil production for each of the 10 largest operators, and how much they already produced versus projected production. Just use the “Operator” selection if you wish to see other operators compared here.

The bottom chart shows for all selected wells the estimated ultimate recovery (EUR), for each of the basins. The aim here is to show the differences in well EURs for each basin, but also how these recoveries are distributed over time. This latter can be seen by the colors used; for example, the blue color at the bottom is the portion that is recovered in the first year on production.

Full Story


As noted, I’ve estimated the future output of each individual well (in total 56,641 horizontal wells). Each of these wells started before July 2016, but I’ve used actual production data through October 2016. This way, for each well at least 5 calendar months of production history were available, which was used to estimate future production. The method used has not changed since the last version, but here follows a brief explanation of it.

The key assumption on which the method is based is that the decline behavior of wells in each of the basins hasn’t changed materially. As I’ve shown in the previous posts, although there are significant changes in initial production, the decline behavior afterwards appears so far rather similar.

For each basin, and for each well age (in months on production), I’ve clustered wells by their actual production rate. For each of these clusters, I’ve determined the average actual decline rate seen afterwards. To project the output for a well, the algorithm first searched for the matching cluster to which this well belongs, based on its age and production rate. Then, the decline rate that historically was seen for the wells in this cluster, was applied to this well.

For far-out months, for which very limited data exists, I’ve used exponential terminal decline rates depending on the basin (8% for the Bakken, and 10% for the other basins). Also, I used an economical limit of  6 bo/d, after which a well would stop producing. These values are just estimates that I deem reasonable, but very limited data exists to support them. If you belief that other values for these parameters are more appropriate, you could estimate the adjusted results.

Note that slightly different estimates for these terminal decline rates, and economical limits will not greatly affect these results, as most oil is recovered in the first several years, and for this period extensive data already exists.

Discussion of weaknesses of this method

  • Decline rates are estimated based on all the wells in the basin, and not for the area (county/field/formation/depth). Basin-wide results will therefore be more accurate than more local results.
  • I have not used any information on the completion methods used for each well, and therefore completely ignore this, while acknowledging that this may strongly effect individual well performance.
  • Only the latest known production rate is used to determine which decline rate should be applied. In cases where the most recently reported production rate is not a good reflection of the actual state of the well, the projected output will not be correct either.
  • A small number of wells in these basins are gas wells, so they may still continue to produce even when their oil production has reached very low levels. This explains some of the (minor) sudden drop after October 2016; several wells that recently still continued to produce at low oil production rates would stop producing according to the method described above. This causes some downward bias.
  • I’ve tried to exclude the results from refracking; wells that were refracked were not used to determine projected production declines for other wells. As operators may continue to refrack some of their wells, the future output is likely to be a bit higher than indicated here. Therefore, also this effect may underestimate future output from these wells a little.

Changes since the previous version

I’ve made a few changes since the last post on this topic:

  • Wyoming has been added to this data set.
  • In North Dakota, the data now contains wells from 2005 & 2006 as well.
  • A few hundred wells in the Permian basin in West Texas were removed (7% of the total horizontal wells), due to low accuracy in estimating their individual production histories.
  • As mentioned, wells that started in the first half of 2016 have now been added.
  • Instead of using an economic limit of 8 bo/d in the Bakken, I used 6 bo/d now. The only reason I did this is to make it inline with the other basins, as I have no comprehensive data on this topic.

Differences with the previous result

I intend to regularly (maybe twice a year) revise this post, and then to compare the new results with the previous ones.

Due to differences in coverage, as described above, the results are not exactly comparable. Despite that, you can see that the overall shape of the total production profile is very similar between both versions. In Jan 2025, the projected output of wells that started before 2016 is around 0.5 million bo/d, in both the new and the old version. In general, there appears to be a small downward revision of projected output, given that the new version contains more wells.

Looking at the results in more detail, I found several minor changes:

  • The production peak in March 2015 is now higher at 4.17 million bo/d, instead of 4.0 million bo/d. This was historical data in both presentations, and this shows the effect of the overall increase of wells in the new data set.
  • October 2016 production, which was projected in the previous version, and on which we now have actual data, is in the new version about 0.25 million bo/d higher (2.35 vs 2.1 million bo/d). Part of this can be explained by the increased number of wells, but I think that some of this higher production also comes from the higher initial production of the wells that started at the end of 2015, compared with earlier wells.
  • Besides that, I noticed that in the previous version, my coverage of wells that started in the 2nd half of 2015 in Texas was not yet complete: if you select only the Texas basins, you’ll see that in Dec 2015 the production of these wells is now more than 0.1 million bo/d higher (almost 2.2 million bo/d, vs below 2.1 million bo/d in the previous version).


I would like to thank Jim Brooker for reviewing several drafts of this new Projections presentation, and for providing several excellent suggestions.

I’ve planned to publish a new update on the Eagle Ford by next week Tuesday, followed by one on the Permian.

For this presentation, I used data gathered from the following sources:

  • Colorado Oil & Gas Conservation Commission
  • Montana Board of Oil and Gas
  • New Mexico Oil Conservation Commission
  • North Dakota Department of Natural Resources
  • Texas Railroad Commission. I’ve estimated individual well production from well status & lease production data, as these are otherwise not provided. About 7% of the horizontal Permian wells in Texas are excluded, as these were mixed with too many vertical wells on a lease, making reasonable well profile estimations impossible.
  • Wyoming Oil & Gas Conservation Commission


The above presentation has 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.
  • Tool tips 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.