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 from all 21,081 horizontal wells in the Eagle Ford region, that started producing since 2008, through June.
In the first half of this year, oil production from horizontal wells has hovered just above 1.2 million bo/d, while gas output stood at about 5.8 Bcf per day.
Unlike the Permian, production growth is rather timid in this area. Although the ‘Well quality’ tab shows that well productivity has improved in the last couple of years, the rate of improvement is lower, and EURs are as well. That may be the reason that just ~80 rigs are drilling horizontal wells here, versus more than 400 rigs in the Permian.
The final tab (‘Top operators’) shows that the 2 of the 5 largest operators, EOG & ConocoPhillips are producing at or near their all-time high.
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.
The 538 wells that started production in Q4 2017 are so far showing the best results; they have recovered on average 162 thousand barrels of oil in their first 7 months on production.
You can see that many wells (close to 80% of the total) are now below a production rate of 50 bo/d.
The Eagle Ford has also a significant gas window, so the results can be quite different geographically. If you look only at the heart of the play, in Karnes and DeWitt counties, you will find significantly better results. However, here it appears that since 2014 wells are declining steeper than before, despite starting at higher initial rates. This can be seen in the following screenshot from our ShaleProfile Analytics service, in which the production profiles are shown for the wells that started producing between 2014 and 2017:
Normalizing for the slight increase in average lateral length over these years (or the far larger increase in proppants per foot), this effect becomes stronger.
[Updated] On October 15th or 16th we will have a new post on all 10 covered US states.
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.
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.
Enno, or anyone. I see that in Eagle Ford there are 4,000 wells producing less than 10 b/d.
What is the cut-off level of production while still being profitable? I guess each well has a certain amount of fixed costs attached to it irregardless of production level, implying that at some point, it is better to shut it down??
5 b/d * 60 wti * 365 = Roughly $100k per annum. Is this enough to cover fixed operating cost?
In the Eagle Ford there is also a significant gas window, and depending on your definition, there are about 2,900 gas wells (14% of the 21k wells). Most of these produce not much oil, so they will also be part of those 4,000 wells. Within our analytics service, it is possible to select only oil or gas wells.
Regarding economic limits, I would recommend listening to the input from those who have access to actual cost data, like Mike Shellman.
Alex, as an operator familiar with shale oil costs I believe economic limits in the Eagle Ford are somewhere around 12-15 BOPD at current prices. I am unclear why anyone would produce a 10 BOPD EF well as one significant well intervention (workover) per year would wipe out any marginal net cash flow. Ten BOPD wells may still be operated on multi-well leases, or units, but only because of economies of scale, or might otherwise be produced to avoid plugging and decommissioning costs. Hope for higher oil prices springs eternal for the shale oil industry. As does praying on ones hand and knees that interest rates don’t go much higher.
Interesting. So we have nearly 50% of producing wells that is below 25 b/d or nearly 10,000 wells that will be plugged within a not so distant future. Add that to increasing decline rates and the growth trajectory will be severely reduced.
About 60% of Eagle Ford wells at 60 months are at 20 b/d or lower (total wells with at least 60 months of output is 7847 wells.) If we look at wells that have been producing at least 36 months 33% of 15935 wells are producing 20 b/d or less. Of the 8088 wells that have ben producing more than 36 months but less than 60 months, about 7% of those wells are producing less than 20 b/d. All of these numbers are based on the data found here at shale profile.
Can anyone comment on why the total production from the Eagle Ford looks so much different versus the other basins? Permian, Niobrara, and Bakken have all seen significant inflections in production in 2017 and 2018 whereas Eagle Ford production remains relatively flat since 2016. Did Eagle Ford have more limited tier-1 acreage? Are we seeing the parent-child issues more significant in the Eagle Ford for some reason?
I hope you will get more responses.
What I see is that the rate of well productivity improvements in the Eagle Ford were the lowest of these 4 basins in recent years.
What also surprises me is that I see (in our advanced analytics service) that laterals are the shortest in the Eagle Ford in the past year (even shorter than in the DJ-Niobrara), while proppant intensity (pounds/lateral ft) is the highest.
Brendan, I operate in S. Texas and have RI interest in EF wells. The best answer I can give you is that the Eagle Ford is just not as good of a resource bed as other basins and I suspect that has something to do with TOC, brittleness, clays, etc., etc. There are awesome wells along the liquids-rich leg in DeWitt and Karnes Counties; in the end, however, I think folks will be stunned at the percentage of Eagle Ford shale oil wells that never reached pay out. From a business standpoint ( the only way I can view these sorts of resource plays), even with the highest product prices in America, the Eagle Ford is a financial disaster.