Enno Peters
This is an older blog post, you will find one on more recent data here
This interactive presentation contains the latest oil & gas production data through March from 20,615 horizontal wells in the Eagle Ford region (TRRC districts 1-4), that started producing since 2008.
Growth is tepid in the Eagle Ford basin, and recent oil output remains well below the high set in March 2015, even after upcoming upward revisions.
Although well productivity has also improved in this basin, as shown in the ‘Well quality’ tab, the effect has been more modest. After normalizing for the increase in lateral length, it almost disappears, despite that the amount of proppants used has doubled over the past 4 years.
EOG is the largest oil producer in this area with ~ 250 thousand bo/d operated production capacity (see the ‘Top operators’ tab).
The ‘Advanced Insights’ presentation is displayed below:
In this “Ultimate Recovery” overview the relationship between production rates, and cumulative production is revealed. Wells are grouped by the quarter in which production started.
For example, the thick blue curve, representing the 1,024 horizontal wells that started in Q3 2013 peaked on average at a rate of 361 bo/d, and are now just below 24 bo/d, after having recovered 133 thousand barrels of oil and 0.5 Bcf (you can click on this group in the color legend to highlight the related curve).
In comparison, the 474 wells that started in Q4 2017 peaked at double the rate. But will they also double the ultimate oil & gas recovery? It’s too early to tell for sure, but noting that the decline behavior has been relatively predictable in the past, it appears they will fall short of that.
Later this week I will have a post on all 10 covered US states, followed by an update on North Dakota.
We will be present at the URTeC in Houston later this month, so if you would like to meet us, or learn more about our upcoming analytics services, I hope to see you there.
You can follow me here on Twitter: https://twitter.com/ShaleProfile
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.
News, trends and data for the US upstream industry
Novi Energy Newsletter
12 Comments
Because projected UR is so poor in the Eagle Ford operators are now making a very sorted effort at fabricating lower D&C costs, to make the picture appear rosier than it is. Basically the same well design in the Midland Basin that is costing close to $9.5-10.0MM, for some reason in the EF trend is only costing $5.5-6.0MM, so operators all say. But even at those imaginary well costs, and a net back oil price of $27, after all costs are deducted, new wells with greater IP180’s will struggle to be profitable.
Years ago a number of my colleagues and I estimated that the percentage of HZ EF wells that would pay back land, drilling and completion costs would be less than 40%. I now think that percentage was actually way too high.
I continue to be amazed by your work, Enno; thank you. I look forward to seeing you in Houston.
Mike Shellman
Mike,
Looks, judging by the year-over-year wedges, that the EF is approaching played out.
so much for hundreds of years of “cheap, abundant” oil
Ian
Thanks as always for your insights and support Mike. The pleasure will be mine!
Hi Enno,
You mentioned proppant loadings in the EF have almost doubled in the past four years, what about the lateral lengths? Producers like Conoco seem to be getting bigger URs, I wonder if they are consuming more acreage per well or recovering more of the oil in place..
The well count in Karnes is getting very high considering only about 2/3 or some 1300 km2 appears to be getting drilled on the maps. That would mean 2.3 wells per km2 and an average of 217 meters between laterals assuming 2km lateral length on average. Not sure how realistic these assumptions are, but it will be interesting to see how long they can keep increasing productivity with 400 or so wells per year.
Thanks,
Sjoerd
Hi Sjoerd,
Lateral lenghts have also increased here, but less than proppant loadings (by ~30% in the past 4 years). I will show more about that in our soon-to-be-released analytics portal.
There are also upper and lower EF wells, and some companies even do 3 levels, so it is doubled or tripled density of number of wells like wine bottle stack. This could reduce the spacing effectively.
from the Year-over-Year production, EF looks more like Haynesville before 2015, which has long been declared as DEAD.
Shale oil or shale gas sustainability in America will ALWAYS be determined not by production rates, but by profit. Private enterprise runs the show, not government. Far too many people now associate increased productivity with success and do not bother to look at costs (longer laterals, more sand, etc.), or the burden that ‘old’ debt places on ‘new’ production, and the bottom line. Higher productivity is a metric that day traders like to use in hopes of talking each other into stock bumps.
The overall financial plight of the shale oil industry, at least, has not gotten better with higher prices and increased productivity. It has actually gotten worse. So called, shale “resilience” is simply a function of how much more borrowed capital was thrown at the exercise. Debt has increased and Tier 1 ‘core’ areas are getting hammered with wells that is causing GOR’s to increase and decline rates to steepen.
while many OPM operators are seeing their EF wells on the miserable situation, there are a few bright spots.
1. COP and EOG & MRO, their EF wells look like Pioneer’s Midland wells in the past couple of years — improving super fast; and COP’s wells prior to 2015 are probably the best among shalers in all basins; while EOG and MRO both have decent wells prior to 2015.
2. CHK is trying to repeat their work in Haynesvilles, with wells prior to 2015 subpar compared to Bakken wells, but not that bad; while improvements in the past year looks good.
Seems that rest of EF OPM operators are not doing as well as the above 4 majors, why?
Some critics like Art only picked out bad apples in EF or use the average, and support similar conventional wisdom that EF shale is dead like Haynesville.
@ Nuassembly
If you look at EOG investor presentation. They are drilling wells in 2018 on 330 ft spacing. I can tell you that is to close. Look how bad EOG 2018 wells look.
Look at the 2018 Eagle Ford wells and tell me what you think.
If Eog is the best operator with the best acreage and they are down to infill with 330 spacing the Eagle Ford in past peak and is on its tail of the production curve.
What do you think?
Just read this link, and wonder if we could find out similar conclusions here as Drilling Info did,
https://www.epmag.com/after-25-billion-barrels-eagle-ford-has-more-oil-coming-1672101#p=full
“Gilmer reviewed several pairs of E&Ps and their relative success vs. one another. EOG Resources Inc. (NYSE: EOG), for example, performs highly on lower grades of rock compared to the median among peers in similar rock grades, but not as well in the best rock grades when contrasted with the highest performing peers.
On the other hand, ConocoPhillips Co. (NYSE: COP) performs above the mean vs. peers across all grades of rock. ConocoPhillips employs an aggressive choke strategy and the company’s well production tends to be better over time vs. peers when using cumulative oil as a yardstick.
Gilmer presented an example of two companies operating side by side in the same geography, and in the same grade of rock. Those companies displayed significant differences in cumulative oil production. Gilmer also spotlighted a recent transaction where the purchasing party performed below the levels of the selling party.”
COP claims that their EF well are cash machines.
https://static.conocophillips.com/files/resources/eagle-ford-investor-field-tour-final-040318.pdf