This is an older blog post, you will find one on more recent data here
This presentation contains the latest oil production data from 17986 horizontal wells in the Eagle Ford region, until May, based on the latest production data from the Texas RRC. Of these wells, 15915 where located in the Eagle Ford formation, and all of them started production since 2010.
We can see that total oil production in the Eagle Ford continuous to drop, and faster than last year. Based on preliminary data, I see that in May 92 new wells were brought online vs 68 in April. Due to typical large revisions in the Texas data, I expect that the total production shown here for May ( 1.12 mbo/d) will be still revised upwards by at least 10%, and that recent declines will eventually turn out to be of a magnitude of around 20-30 kbo/d, per month.
This is of a similar size as what we’ve seen in North Dakota, where fewer wells are brought online, but where wells also decline less than in the other basins.
If you switch to gas, you’ll see that the drop in production is much lower.
I introduced a new way to group the total production shown here. If you click on the “Group production by” selection, and choose “Production level”, you’ll see total production grouped by the level of production of each well, during a particular month.
If you do this, you’ll see that in May 2016, less than half of the oil production (around 500 kbo/d) came from wells that produced less than 100 bo/d. By turning to the the “Well Status” tab, you’ll see in the bottom graph that more than 80% of all wells are in this group (<100 bo/d).
This is a general finding in shale oil & gas production: most production comes from a small portion of wells, typically young ones, that have a high production rate.
On the first tab (“Where is the Eagle Ford?”), it is interesting to see that most oil is produced around Karnes county, while gas production is more focused in the southwest of the region (switch product to “Gas” to see this).
In the “Well Quality” tab, we can see the performance of wells since 2012, and I’ve grouped them by the quarter in which they started production. Results are shown in a semi-log plot to reveal better what happens over time.
We can see that initial production has improved since the 2nd half of 2015, which coincides with an overall reduction in completions. Most improvements are in the initial 10 months on production, while the average behavior of wells after this period hasn’t changed much.
EOG is the largest oil producer in the Eagle Ford, as measured by total production (see “Top Operators” tab). If you select only EOG using the “operator” filter, you’ll see that recently EOG wells have increased in performance, on average, in the first few months of production.
I was wondering whether this improvement stems from improvements in well design, or because EOG has focused more on the core areas. To analyze this, I first checked in which counties EOG has its best wells.
EOGs best wells are in Karnes, Gonzales & De Witt. You can see this if you group the EOG wells by “County”. I skip Lavaca, as just a few wells were drilled there.
If we then filter on only those 3 counties, and we group wells by “Quarter of first flow”, we can see that the improvement over time is less than we just saw before. This suggest that an important factor in the recent average improvement has been a reduction in new completions outside these 3 counties.
We can verify this in the next tab “Well Status”:
By selecting EOG, and those 3 counties, and filtering on status “3. First flow”. Now we can see that EOG has reduced completions in those 3 counties, but far less than its overall reduction in completions, which you can find by comparing the results when emptying the county filter.
On (UPDATED) Saturday, September 3rd, I plan another update on the Permian, followed a few days later with a post on all shale regions in the US.
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.
This ongoing effort will enable a wide array of analysis to be brought to this whole shale development and, once again, I thank you for your efforts.
Your comments concerning EOG gets right to the heart of a big issue at the moment, which is, ‘do the huge fracture stimulations of EOG actually increase EUR, or merely accelerate the recovery sooner rather than later? (pulling production forward).
Having accurate, comprehensive data can help answer this, and many other, issue(s).
Thank you for your continuous support.
Do you know off hand what the projected URR has been quoted for the Eagles Ford.
Looking at your charts, the highest monthly CUM I could find was Jan 2014 at 126k barrels of oil after 29 months and currently producing at 51 bbls per day. It looks 200k URR will be a struggle to obtain.
I have not really checked the claimed EURs for the Eagle Ford.
If I would venture a guess: I expect that wells in the best performing counties (De Witt, Karnes & Gonzales) will do on average in the order of 200-250k BO, in addition to 600-700k MCF. I recommend making your own estimation in the “Well Quality” tab, with these counties, and selecting the Eagle Ford formation.
Hi Enno. Really interesting to see how the wells compare between different basins. But it would have been nice if you could also add barrels of oil equivalents under “Product”. That would make it easier to compare Bakken and Eagle Ford for example, as Eagle for produces alot of gas.
I did not add BOE, as I view it as a highly flawed metric. Most often, gas is converted using a 6:1 ratio, based on heat equivalency, even though the economic value of these 2 products is quite different from this ratio. Furthermore, as can be easily seen, the decline profiles of these 2 products is also quite different.
I often compare it with the gold industry : you don’t see gold companies lumping their gold & copper production together, based on weight equivalency.
As Einstein is reported to have said : “Everything should be made as simple as possible, but not simpler.” I think this also holds for oil & gas production.
Therefore, I’ve made it as easy as possible to see both product streams separately, with just one selection. I recommend considering both product streams, when evaluating well productivity.
I see your point in that the decline profiles are different for oil and gas. Gas appears to decline slower. So it could make you draw the wrong conclusions if you are not aware that the decline curve would look different if the gas share changes. Hower I don´t agree that the price difference is a reason. Price changes over time and in most of it is used for energy. So in the end it´s the energy we are after. I think the more information the better :). But you should of course be aware of the limitations in the information. Anyway it´s nice page with lots of good information.
This is wild- If the data is correct check out Well Quality / Operator- Marathon/ County- Karnes/ Grouped by Quarter for 2014 and 2015.
Classic Interference or something else?
Interesting observation Jim.
It indeed appears that Marathon wells in Karnes are getting worse. I’ve seen this kind of deterioration several times now (e.g. check Whiting in Mountrail, Bakken, since 2008).
I just did a quick check looking at the original lease data, and I belief the results I present here are very reliable (there are 741 Marathon horizontal wells in Karnes, located within 403 leases, so the well-to-lease ratio is not so high).
One note of caution : if you group wells by quarter/year, the end of the tails my contain sometimes very limited wells (as shown in the tooltip), so based on this you can decide which data points in the tails you want to consider.
On another note: I just noticed that an article was written about this post, here:
Congratulations on getting picked up by real money. You better make sure all your algorithms and data are as correct as can be- once this site gets picked up by the analyst community the company engineers will be picking it apart. Which can only be a good thing to get the best picture, IMO.
It is interesting that the SEC made a fraud case against Breitling Energy of Dallas and Geo Joe Simo on the basis of-
The bad projections, the SEC says, happened because Simo “took historical production of the best performing wells within a predetermined proximity of the proposed drilling location and assumed those figures as the baseline for his projections.”
Are baseline and type curve synonymous?
I’m not worried about more scrutiny, and invite everybody to check the data I provide. I have several methods in place that reduce the chance on errors, but there is always a risk. For most states, the data collection is rather straightforward, which significantly reduces such risks. Texas has the most issues, but I’ve also build in the most safeguards for this state.
I still should work on a document to describe exactly where and how people can check the provided data, and with some further explanation of the algorithms used for Texas (and to a lesser extent, Pennsylvania), to understand the limitations.
I care a lot about data quality, and use my own site extensively for my own uses as well. Therefore, I can say that I will take any reports of discrepancies very seriously.
“It is interesting that the SEC made a fraud case against Breitling Energy of Dallas ”
That’s a very interesting story. I’ve always wondered how the projected EURs and reserves are determined, and whether bias is removed from these processes. If companies are only completing now the best wells, with very large laterals & frac sizes, will those well results also be used as the baseline for all undrilled/uncompleted well locations in the neighbourhood?
Tell me why there is apparent overlap in the projected and historical. Which one forms the cumulative curve?
CLR 2014 Bakken Projected.
The reason for the partial overlap, is that some wells started production early in 2014, and some late. So, you can expect that (as these well profiles are shown by the YEAR in which they started to flow), you can find 11 months overlap when looking at the historical & projected production profiles for a certain year.
The cumulative graph shows the average cumulative production, counting both historical & projected production.
Let me know if this clarifies your question.
I think I get your point here. Do you happen to what know the spacing on Marathon’s horizontal wells and how many wells Marathon is producing/ drilling/spacing unit?
…”(but a terrific one)”…realmoney has it spot on!
Just curious, when are you next intending to update Marcellus/Utica?
Thanks again Enno for your incredible work!
> Just curious, when are you next intending to update Marcellus/Utica?
I’ve not decided yet when I’ll do a separate update on the Marcellus – maybe end of next week.
But do note that in every US update, I include the latest data for all the 6 states I cover, including Pennsylvania. So if you’ll
1. go to https://shaleprofile.com/2016/08/05/us-update-until-2016-04/
2. And either filter on state (Pennsylvania), or basin (Marcellus)
=> you’ll find the latest data I have on oil & gas production there. Just switch to “gas”, as that will be more relevant.
Amazing work here, thank you.
I am wondering how you were able to get individual oil well data from the TX RRC given that it is reported by lease # and not well # (API). How did you manage to work around that?
For Texas, all well profiles are estimated, using an elaborate algorithm that takes the total monthly lease production, and divides this production over all wells in the lease, according to:
– typical well profiles for this type of well (horizontal/vertical), county, and starting year
– the known completion date of each well
– the detailed status of each well
Given that the average ratio of wells to leases is not that large ( < 2.0 ), this algorithm comes up with pretty good results, on average, especially when looking at a little larger regions than single wells (e.g. per county, or operator). The algorithm guarantees further that all lease production is consumed in this way by all wells, so that there is less change on a structural bias in the results. I intend to describe the algorithm in a more complete way in the future.