This is an older blog post, you will find one on more recent data here
These interactive presentations contain the latest oil & gas production data from all 19,047 horizontal wells in the Permian (Texas & New Mexico) that started producing since 2008/2009, through November.
November oil production came in above 3 million bo/d (after revisions), at a y-o-y growth rate of 1 million bo/d. More than 4,200 horizontal wells were completed in 2018 through November, double the number in the same period in 2016.
Average well productivity has only increased slightly since 2016, after big gains in the years before, as the ‘Well quality’ tab shows.
The 2 largest producers, Pioneer Natural Resources & Concho Resources, are now above 250 thousand bo/d of operated capacity (see “Top operators”).
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 year in which production started.
If you extrapolate these curves, you’ll find that recent wells (2016/2017) are on a path to recover on average about 300 thousand barrels of oil, before their production rate has fallen to 40 bo/d.
Associated gas production is high in the Permian, at well over 9 Bcf/d. If you switch ‘Product’ to gas, you can find the average gas production for the same wells. Newer wells are on average likely to recover 1.5 Bcf of natural gas or more.
Today (Tuesday) at noon (EST) we will also present an update on the Permian and the Eagle Ford on enelyst, where we will share our insights in these basins based on the latest data.
Last month many of you subscribed to our analytics service, which offers access to more dashboards, well data, and more recent production data. Thank you! The cheapest subscription version, Analyst, costs just $52/month per user, and you can try it for 1 month for only $19. With this, you will experience some of the analytical power of ShaleProfile Analytics.
Later this week we will have a post on the Eagle Ford.
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.
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.
Why did PXD report only 194 MBOD for oil for fourth quarter 2018 while your numbers are much higher?
We publish the reported production from all horizontal wells by operator.
PXD also owns some conventional production, it may own interests in non-operated wells, but most importantly, others own interests in its wells. PXD only reports its net production in its financial statements.
I have a really hard time rectifying every poster’s bearish view with Enno’s data, and this is especially true for the Permian data.
My approach is to look at Enno’s brilliant chart of Daily Production to Cumulative production. I look at Quarterly vintages. I start by highlighting 1q14, and I highlight new quarterly vintages one by one to see the changes over time.
My problem is that all I see is improvement in pretty much every vintage. The most surprising element is that older vintages appear to be flattening out, implying larger EURs for these vintages.
Here is what I see in case of interest:
1q14: flattening out in later months, but ~275k EUR
2q14-1q15: continued improvements. 1q15 vintage starting to flatten out. EUR of ~350k-400k EUR
3q15-2q16: wow. 4 straight quarters of steady improvement in trajectory.
3q16: first inline quarter in a while. EUR now looking like it’s >500k.
4q16-1q18: trajectory in line with 3q16
2q18-3q18: too early to tell. Looks inline with IPs better than 1q18
Am I reading these charts incorrectly? Or differently from other readers? I realize we need to consider changes in proppant usage and/or lateral length, and I don’t have the data for that, but if the question is can the Permian offer up a lot of wells with >700k EURs on a boe basis, I think the answer is clearly “yes”.
And if we look at the Bakken using a similar exercise, it’s not nearly as good, but there have been improvements, and based on the four 2017 vintages, 400k oil EURs seem achievable (although recent vintages may have some concavity problems). And I think this was achieved without big changes in proppant and length.
If that’s true, isn’t Shale going to produce a ton of oil and satisfy a lot of demand growth by itself? I realize many executive teams may be lying about their own EURs and such, but from a global s/d perspective, it seems like shale is going to be a very big contributor for a number of years.
Would love to hear what I’m missing.
Hmmmm. Are you projecting EUR?
For Q1 14 – After 56 Months (on Production) average well produced 131,915 bbls of oil.
For Q1 15 – After 44 Months (on Production) average well produced 154,837 bbls of oil.
For Q1 16 – After 33 Months (on Production) average well produced 194,789 bbls of oil.
For Q1 17 – After 23 Months (on Production) average well produced 184.204 bbls of oil.
For Q1 18 – After 9 Months (on Production) average well produced 120,479 bbls of oil.
How long these wells will remain economical… it’s still unknown at this time. Some companies are stating up to 40 years, but in reality it looking more like 7 to 10 years before they become uneconomical.
Even if you include gas on a BOE basis (and gas in the Permian only gets $8 to $12 a BOE) the numbers still won’t come close to your numbers.
By the way it’s looking like the newer wells are producing more gas on a percentage bases than older ones.
There’s no doubt that US shale will produce a lot of oil/gas, but is it being produced so that those invested in the shale drillers will get a return on investment?… that’s the multi-billion dollar question.
Thanks for your response.
Yes, apologies if that wasn’t clear, I am projecting EURs. I use a very rough method, but I believe it was even endorsed by Enno himself, and that’s simply to extend the current trajectory of the vintage at a straight line until it hits the x-axis. I realize production is no longer economic below certain thresholds, so eventually there will be a cliff, but I have tried to be relatively conservative in the extrapolation, so hopefully this is less of an issue.
In the numbers you posted, it’s quite clear there has been massive improvements in potential EURs. Look at 1Q17, with 184k bbls of oil. That’s quite comparable with 1Q16 despite ~10 months less of operations.
And then look at 1Q18. It’s at 120.5k bbls of oil after 9 months. The 1Q17 vintage was only 106k bbls after that same time period. So it seems like we are seeing continued improvement.
I think it’s harder to really see the improvement if we are just comparing individual datapoints. IMO, the best way is to look at the Ultimate Recovery tab and look at the trajectory of each vintage.
In response to your earlier question about any bearishness (questionable economics) perceived from Shaleprofile data, this is how I reconcile it. The average Permian well has an implied EUR of 500K B assuming a linear extrapolation to an economic limit of 10 B/d. This might be optimistic if terminal decline rates trend more hyperbolicly or even exponentially, which would bend the curve toward a lower EUR. Someone earlier alluded to how we don’t how many of these wells will perform later in life, especially given relatively short production histories.
Hair-cutting the assumed 500K B EUR by an average NRI of 25% yields 375K B. I also simplistically assume byproduct gas & NGls covers operating cost, and 10% discount to benchmark oil prices for basis differentials and production taxes. This implies gross cash flow of $20MM per well with $60 WTI, which adjusted for a PV factor of 50% (a good average for unconventional PDP production discounted @ 10%) yields $10MM PV per well. With wells costing upwards of $10MM, the investment PIR is barely 1 before lots of other costs such as G&A, G&G, infrastructure, land, etc.
Would love to hear feedback.
The wells become uneconomical somewhere between 10-20 bo/d, depending on the oil price and royalties. So that is where the spigots are turned off. The higher the cut-off rate, the lower the EUR.
Comments have been quite bearish because operators are projecting huge powerpoint EURs which are clearly not based on actual production trajectories. Producers appear to be burning money when oil is at $50 and EURs are below 400k.
Michael and Mikko,
Keep in mind that the improvement in EUR is in part due to longer average laterals and higher numbers of frack stages as well as higher levels of proppant use in the Permian basin over time. Also if you look at well profiles by quarter for 2016 to 2018 wells you will see that most of the increased output is over only the first 18-24 months, after that the well profiles all seem to fall to about the 2016Q3 level or lower, if you focus on the 2016Q3 line and assume a more realistic cutoff of 15 b/d as the economic limit the EUR for oil only (the natural gas and NGL does not contribute that much to net income) the value is about 375 kbo, that is a pretty reasonable estimate unless oil prices rise to $85/b or more, in that case the economic limit might move closer to 10 b/d and EUR might rise to 420 kbo.
That is how I see it, EUR is likely to be 400+/-20 kbo from 2017 to 2023 (I expect optimal well design has been reached in 2018) after that sweet spots will run out of room and we will see decreasing EUR as completion moves to less prospective areas of the play.
Hi Dennis, yes I realize there has been an increase in lateral length and proppant usage, but I don’t have the adequate data to adjust for this. I will put it on the to-do list, and thanks for the flag.
I’m starting to see why there are so many oil bears who point to shale’s prolific growth yet there are also so many shale bears on this site and elsewhere. My preliminary take is that oil bears focus on the overall shale EURs (the fact that it seems reasonable to expect >500k oil EURs on recent vintages) and continued improvements in EURs by vintages (consistent improvement in trajectory of vintages from 2013-2017, and at least a bump in IPs on recent vintages). That seems negative for the global oil s/d.
Meanwhile shale bears focus on the promotional nature of management teams with their PowerPoint EURs and also focus on the bad and/or unproven unit economics of shale in general. Even though there has been improvement in EURs, this took investment, it’s not clear the industry is generating >10% IRRs on a per-well basis.
I guess some outstanding questions are:
What are true unit economics on vintages today?
Are ROICs improving? If so, at what pace?
If ROICs are uncompelling and not improving at a fast rate, when will investors stop funding these aggressive growth programs?
I use the data from shale profile and fit a hyperbolic to recent vintage wells (2016 and 2017 data), I also consider the economics, except I ignore natural gas income (as natural gas spot prices are so low and a lot of the gas is flared), for oil only a breakeven price of about $57/b at the well head (maybe $62 to $67/b at the refinery gate) is needed for breakeven at a 10% annual discount rate (well cost equal to discounted net revenue over the life of the well), I assume the well is shut in at a monthly net revenue of less than 15k in 2017$ as I assume an average monthly fixed cost of 15k for downhole maintenance. EUR by this analysis (oil only) is 365 kb for a 9 million dollar average well cost at $57/b at wellhead. If oil price goes up to $80/b EUR increases to 374 kb and at $95/bo at well head EUR increases to 378 kb with well shut in at 8 b/d. At $120/bo at wellhead EUR is 382 kbo and well is shut in due to economics at 6 bo/d. The 750 kbo well exists, but that is the top 1% of the productivity distribution, the mean well is about half that productivity and most wells will be shut in before reaching 10bo/d unless oil prices rise to more than $78/bo at the well head.
Brendan…. Here’s some articles that point out some of the problems in shale a whole lot better.
On the surface things look rosy, but when you dig a little deeper…. not so much.
For those without a subscription to WSJ, here’s a free version of that WSJ story