- How much oil will existing US shale wells produce in the future?
- How much oil will a typical well produce in each of the basins?
- How much oil have operators already produced from their existing wells, and how much can we still expect from them?
To answer these, and related questions, I have created the presentation above. It contains three main overviews, which you can see by clicking on the “tabs” on top of it:
- Projected Production. Here you can see the oil production of 46408 horizontal wells that started production before 2016. The view is split at January 2016, after which the production has been projected using a method I will explain below.
- Production Profiles. Here you can see the actual, and projected production profiles for all wells, on which the first and third overview are based. You can use the “basin”, “operator”, and “first flow” selections to narrow down the selected wells. With the “show production” selection, you can see for the selected wells the actual (historical) production, the projected production, or both.
- Ultimate Return. This overview shows for each operator the amount of oil already produced from its wells, and the amount that is estimated to be produced from its wells in the future. Also, it shows for each basin, the estimated ultimate return (EUR), including the amount of oil that can be expected each year on production.
All overviews use the same 46408 horizontal wells that started production before 2016.
Just to be sure, this presentation doesn’t show what actual US shale production will be in the future (I don’t know); as we’ve seen in the past, with abundant capital available, large increases are possible. Future production is simply unknowable. Still, by using all available production data so far, and the assumption that well behavior will not change much, I belief a reasonable estimation can be performed of what existing, producing, shale wells are going to produce. That is what this attempt is all about.
This is the first time I’ve put up this presentation, and that increases the chance somewhat that there are still some issues. If you find anything strange, please let me know.
For those interested in details, I will now explain the method I used to make these projections in some more detail.
I’ve estimated the future output of each individual well, for which I had a complete production history (= 46408 wells). The key assumption on which the method is based is that the future behavior of wells will be similar as the behavior we’ve seen in the past. As I’ve shown in the previous posts, it does strongly appear that wells behave rather similarly as past wells, especially after the initial 12-18 months on production.
For each basin, and for each well age (month on production), I’ve clustered wells by their actual production rate. For each of these clusters, I’ve determined the average actual decline rate. In order to make an individual well projection, I determined the age for each well and to which cluster it belongs, and then applied the related historical decline rate.
For far-out months, for which very limited data exists, I’ve used terminal decline rates depending on the basin (8% for the Bakken, and 10% for other basins). Also, I used an economical cut-off of 10 bo/d for Bakken, and 6 bo/d for non-Bakken wells, after which the wells stop producing. I think that these are reasonable estimates, but will not try to defend them. Instead, by explaining in some detail the method used, I hope that you can understand the results, and allow you, based on your own knowledge and expectations, whether you want to adjust the results in some way.
Note that different estimates for these terminal decline rates, and economical cut-offs will not greatly affect the outcome, as most of the production happens in the first several years, and for this period extensive data already exists.
Some 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 no information on the completion methods used for each well, and therefore completely ignore this, while acknowledging that this may strongly effect individual well returns.
- Only the latest known production rate is used to determine which decline rate should be applied. A better way is to also use the production trajectory of the past several months.
I will probably make further enhancements to this method, and the parameters, in the future, although I don’t expect significant differences from this result.
I’ve tried to exclude the effect of refracing, by excluding production histories after an apparent refracing event. As some of these legacy wells are likely to be refraced in the future, future production will be a little higher (a few percent).
Note that for wells for which I have accurate production data after January 2016, I’ve used that, instead of estimating it.
Gas production is completely excluded from this presentation.
On Friday afternoon I plan another update on North Dakota.
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.
- 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, and include or exclude categories.
- 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.
Nice work, Enno. Will need to take the time to look at it (since you publish a tool, not the views from it that tell a story.) Few comments:
1. “As I’ve shown in the previous posts, it does strongly appear that wells behave rather similarly as past wells, especially after the initial 12-18 months on production.” This is kind of a big comment. Maybe they behave the same, but I certainly haven’t seen it explained to me so I just readily “get it”. And for that, the “I made a tool, people can play with it” is not sufficient explication! 😉
2. Looking at grouping wells by quarter, for ND, it does seem that there has been some high grading and 16 and maybe 2H15 wells are running noticeably better than the rest. Whether the cum curve bends down or they “keep” the extra oil or even widen the gap over time seems to me still in question. [I realize 16 is out of scope for presentation above. Just making the observation.] I guess if you are just treating them like bigger normal wells, though, then you are being generous to them.
3. 10% terminal seems high. Maybe it is right, but I just like to know where you got it–I hope not a comment on PO or POB.
*Oasis assumes 6% here: http://www.oasispetroleum.com/wp-content/uploads/2014/11/2014-11-OAS-IR-PresentationvFINAL.pdf
*USGS has some assumption within their published Bakken two-step EUR model, but it doesn’t seem explained what the exp decline % number is. Maybe you can extract it.
*Here is a thesis that tests many models, but their ARPs to terminal decline chosen to test was 5% terminal decline: “A STUDY OF DECLINE CURVE ANALYSIS IN THE ELM COULEE FIELD” [No url, because two links activates spam control.]
*This journal issue has several articles on decline curves, but towards front mentions both Brigham and “generic” company in the Bakken using 5% terminal rate: The Journal of SPEE, Spring 2012 (google for the url)
I usually fit a hyperbolic profile to the average well in the Basin and when the decline rate reaches about 8%/year for the hyperbolic I switch to exponential decline at 8%. I use an economic cutoff of 7 b/d based on advice from shallow sand and Mike Shellman.
As Enno said, we don’t know what future output will be, just a somewhat less conservative take.
Thanks. I found these decline rates, by looking at the actual decline rates of wells already several years on production, in the different basins, after correcting for possible refracs (I did this a few months ago). It’s an interesting, and important topic, and I’m willing to regularly look at these decline rates, and adjust my model if they appear to have changed. However, the difference between a 10% or 6% terminal decline rate, will not be extremely large for total production, and less so on the economics of the well.
It’s a relatively important topic, but I wanted to leave the discussion on this outside the scope of this presentation. If someone prefers other terminal decline rates, it’s not so difficult to make a rough estimation on how it would affect the results presented here.
As I’ve access to the full production histories of almost all horizontal LTO wells, I will just look up the actual decline rates once more data comes in, instead of trying to find what others are saying about it.
Of interest to this debate: http://www.rystadenergy.com/NewsEvents/Newsletters/UsArchive/shale-newsletter-august-2016
Thanks for sharing! A very interesting article..
I do have a few comment though:
– It’s really a pity that they count “BOE”, instead of oil and gas separately. These 2 streams have different decline profiles, and it is totally absurd to combine these to based on “heat-equivalent-basis” as seems to be so common in the industry.
– They state in bold: “a typical shale well produces almost half of the ultimate recovery during the first 5-6 years of well lifetime”. As I show in the 3rd tab (“UR”), this is based on my projections too optimistic, even for the Bakken, but especially for the other basins. I do count only oil though.
– The “typical” well they show, seems to be quite a bit better than the average UR I expect for 2015 Bakken wells.
Still, I’m very happy that Rystad is initiating discussion on this subject.
Excelent work. What makes you believe that 2015 wells won’t follow the 2008 profile?
I didn’t put any beliefs in the algorithm, except for the mentioned parameters. Those 2008 wells are all Bakken wells, while only a minority of 2015 wells are Bakken. In each basin, the decline profile is rather different.
I assume you used a hyperbolic fit for these type well curves? The 10 % end point seems valid.
The economic limit for a well will depend on whether its on artificial lift, the amount of water it produces, and commercial terms. These can be highly variable. I also suspect water production will be higher in some zones and geographic sectors. Also, I expect gas to oil ratio to increase gradually. This will complicate matters.
Thanks for your comment Fernando.
Instead of fitting each well with a hyperbolic function, I’ve applied basin-specific, historical decline rates, based on both the age, and the latest production data from each well. I’m not arguing that one approach is better than the other, just that I think that this is quite a reasonable approach, as long as well profiles don’t behave significantly different than before.
After some deliberation, I decided to update some of the parameters used in the algorithm:
Bakken : 10 bo/d (was 15 bo/d)
Others : 6 bo/d (was 8 bo/d)
Terminal decline rate
Bakken : 8% (was 10%)
Others : 10% (was 12%)
There is not much hard evidence yet for either of the old or new numbers. Also, I don’t think that the actual values will strongly differ from these numbers, nor do I think that they will have a great impact on the result.
Great website and data analysis. I have been looking at the RRC data through their website and I was wondering how did you get individual well-level data for Permian? I can only seem to find the lease level data which doesn’t give much clarity when trying to look at each yearly vintage. Any push in the right direction would be appreciated
Thanks, and a good question. Everybody who wants to utilize the RRC data runs into this issue indeed.
I answered this question here:
In the future, I plan to write a more detailed description on how I’ve estimated individual well production, based on the lease production data & individual well data. In the last few months, I’ve further enhanced this algorithm.
Luckily, most leases that I’m interested in (containing horizontal wells that have been completed in recent years), only contain a small number of wells. The average in the whole Texas is even < 2 wells per lease, for these leases. This means that the method I'm using works quite reasonable in most cases (and perfect in the many cases where there is just one well per lease). Unfortunately, there are also a small number of leases, that contain a very large number of wells. The most extreme case is a single lease with 203 horizontal wells. In these cases, the results will not be very accurate. Still, given the available information, the results will be reasonable: the algorithm divides all monthly lease production over all wells, taking into account the actual completion date of each well, its other properties and status, and the typical well profile of that area. Given that there are fewer legacy wells in the Eagle Ford, the results there are more accurate than in the Permian. In the Permian, there are roughly 7000 horizontal wells, located on about 3500 leases. Each state has its challenges (life wouldn't be fun without them), and Texas is one of the more extreme cases.
Makes me wonder about four things:
1. I have read promotional materials that tout horizontal shale oil wells will recover in excess of 1 million BOE. Isn’t that obviousely in conflict with this data?
2. When one factors in published well capital, reasonable royalties,s-10 data regarding overall company expenses on a BOE basis how are most of these wells profitable at a $40, $50 or even a $60 per Bbl sales price of oil?
3. For those companies that are claiming large improvements in EUR over the last couple years via denser fracturing shouldn’t those completions be more costly causing the overall well cost to increase?
4. Is the KING not wearing any clothes or have I missed the obvious?
One important reason for me to start this website was my continuous surprise at how actual production data seemed to differ from production numbers from probably similar sources as to which you are referring.
Also, be aware of the great distortion that is caused by converting gas production to BOE, which is based on heat equivalent (6:1), not based on the more logical, economical value equivalent. Especially gas wells, and oil wells that have a larger gas production later in life, can really distort these EURs if given in BOE (which appears to be the standard).
I find it very useful to use these actual production numbers to estimate individual well economics, like your example. It is also my impression, that for the average well in many basins, the economics look very bleak in the current price environment.
My hope is that people like yourselves, once you’ve seen the actual performance of shale wells in the different basins, help others who may have any misunderstanding about this, by pointing to this source. The states publish lots of data, but this data is not so easily converted into a comprehensive picture, which is what I’m trying to do here. As anyone can easily verify, since my latest ND update, my data matches the state data.
…and you have done a remarkable job, Enno. It is clear to me that a lot of people are now using your blog regularly when seeking, shall we say, “truth in advertising” regarding the LTO phenomena. Your new “well status” tab is very, very cool. When one is aware of the actual net back price shale oil producers receive, after all costs and expenses, the ‘oil production level as a percentage of whole’ charts imply exactly how few of these wells will ever be profitable.
Your work is very important; thank you,
Independent Oil and Natural Gas Producer
My comments would mimmick Mr. Shellman’s. Thank You for the work you have put in this site. I have found it to be truly invaluable in grounding myself in this type of production.
I fear a very large investment bubble has developed in this type of production. Given the US has experienced historically low GDP growth recovery since 2007 and a reasonable component of that growth has been from the energy sector, I am concerned not only for the financial health of the US energy sector but for the potential macro economic effect it may have on the US economy. Hopefully the drop in oil sales price in the last couple of years has tempered that potential effect but given the potential for extremely rapid shale oil production decline should investment cease for any significant period of time things could get very wild.
Mike & OilBearon,
Your praise is highly appreciated and a major motivation for me to keep doing this.
For something that has such a major impact on major economies worldwide, I was highly surprised at how few sources were openly, and without apparent bias, reporting about the developments in shale production, based on all available data.
I think there are many valid concerns regarding shale oil & gas production, and I hope that the presentations here help in answering some of these questions.
I just discovered your site through Seeking Alpha. Kudos for making this information readily available to the public in an understandable format.
If any, what are the greatest uncertainties in you analysis?
In your opinion, how many rigs will it take to keep US shale oil production at 4 million bp/d)? This will obviously depend in which basins the rigs are employed, but a rough estimate would be appreciated.
Thanks for the comment.
> If any, what are the greatest uncertainties in you analysis?
I will assume that you refer to the presentation in this specific post. As we’ve quite good well production data history for young wells, I’m pretty confident that the near-term projection will turn out pretty good ( I expect to be within 15% for total projected production at the end of the 1st year). Its much more unclear what operators will decide to do with old wells; refracking them, otherwise sustaining them, or plugging them. So at the far right, things might turn out differently, also because we’ve only limited history for how old wells behave in the different basins.
“In your opinion, how many rigs will it take to keep US shale oil production at 4 million bp/d)?”
That’s not an easy question, as there is no direct relationship between rigs and production in the short term. The rig count doesn’t tell us how many wells rigs are drilling each month, and how good these wells will turn out to be, and especially whether operators are building or depleting their DUC inventory. Several of these factors depend on data that I’ve not collected.
A slightly simpler question to answer is how many wells should be brought online to keep production at 4 mbo/d.
Reasonable (though still overly simplified) answers can be gotten in two ways:
1. Based on the projected production in this presentation, you can see how much new production should be brought online to keep at a certain level. You can then look at past periods how many wells were necessary to get to such an amount of new production.
2. A simple way to calculate the answer for this in the long run is to estimate the UR for each new shale well. If you expect that the average UR for each new shale well is 200 kbo, then in the long run we need 20 of these such wells each day to get eventually to 4 mbo/d, which means about 600 new wells / month. Based on the rig efficiency, you can then deduce how many rigs would be needed. Of course, this is heavily simplified, as it doesn’t consider changing rig efficiency, changing well URs, and the changing decline of the existing production base.
Hope this helps,