Enno Peters
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 24,208 horizontal wells in the Eagle Ford region, that have started producing from 2008 onward, through November 2019.
Oil production came in again at just over 1.3 million bo/d (after upcoming revisions), as it has since the start of 2019.
Well results have not improved since 2017, as is clearly visible in the bottom chart of the “Well quality” tab. In the core of the oil window, in Karnes and DeWitt, well productivity has slightly declined (select these counties using the “County” filter). This is without taking into account the fact that laterals have gotten longer and proppant intensity has gone up.
In the “Well status” tab the status of all these wells can be found. The bottom chart shows the % of wells by production rate. In November, about 60% of the wells in this basin produced below 25 bo/d. After removing the gas wells (a subscription only feature), this percentage drops to 55%.
EOG’s production fell below the 250 thousand bo/d, a level it first reached 5 years earlier (“Top operators”). Its December production (available in our subscription services) increased again. Meanwhile, Chesapeake set a new production record in November.
The ‘Advanced Insights’ presentation is displayed below:
This “Ultimate recovery” overview reveals the relationship between production rates and cumulative production. Wells are grouped and averaged by the year in which production started.
In this screenshot, taken from ShaleProfile Analytics, you can see all the horizontal wells in Karnes and DeWitt County, colored by the Gas/Oil ratio in the most recent month. The charts on the right show the production rate and gas/oil ratio versus cumulative oil production, by vintage:
These charts reveal that the wells that came online in 2018 became gassier faster than the wells from the year before (bottom chart), while the decline rate has increased (top chart).
Early next week, we will have a new post on all covered states in the US.
Production and completion 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 lease reports.
- FracFocus.org
====BRIEF MANUAL====
The presentations above 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.
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10 Comments
It would be interesting to see both the average horizontal section and number of frac stages vs cum. From the chart shown either the stages were closer, or the horizontal length was increased with progressive years. Based on the 2017 – 2018 lines, EOG seems to have hit a wall as far as well improvement goes.
Your Point about frac stage spacing is the ticket. These aren’t single wells, they are a manifold of vertical wells (stages) tied together with a flowline (the horizontal wellbore). We’ve known since spindletop that the closer you space wells the less each well recovers. So, what started out as 528′ spaced wells in the Bakken has evolved to 120′ spaced wells in the Permian. Yet we expect the historical decline behavior of wider spaced wells to tell us something about the future decline behavior of more closely spaced wells. It does- it tells us the declline is going to be higher.
brookpe,
Describing these wells as a manifold of vertical wells tied together with a flowline is the best description anyone has ever written about horizontal wells.
Thank You.
John-
Thanks. Also fin and tube heat exchanger wells. Nothing new. They are nothing but 120 6 BOPD IP wells that decline at 70% exponential the first year and recover 3000 barrels apiece (at most). They cost $100,000 apiece. Industry promoters have been drilling variants of this crap (Clinton in Ohio) with other people’s money since they moved out of Titusville. A performance graph comparison of production per stage would show just how much economic performance has regressed since the first $5MM wells were drilled in the Bakken.
John-
Isn’t it amazing that if you tried to permit vertical wells 120′ apart you would violate every state spacing requirement in existence because it would be considered a “waste”… so what is it in the end but a technique to circumvent the resource conservation laws? Which laws came into place truth be known because people were making more money by the act of promoting and drilling wells than they were by producing the product. Does any of this ring a bell?
Yes, Brook. It does and I am going to ring it on March 3rd. Not that it will do any good, but I will try to send Ryan Sitton home.
John, mission accomplished!!! America just took a big step forward with regard to pressure preservation, conservation of our last, very (un)affordable oil resources and the REAL long term energy security. Lets hope the other two, and the entire Permian Basin HZ group pays attention and gets their act together. Next on the agenda…water.
Stephen, thank you for your comment.
In our analytics service we do have lateral length information, so you can easily analyze how this has changed by operator, basin, etc. You can start a free trial to see this.
We don’t show the number of frac stages yet, but this is something that we have started to collect.
Indeed it appears that EOG’s well productivity has fallen since about 2017. See this image that shows the performance of all the 3,179 horizontal oil wells that it operates in the Eagle Ford.
Normalizing for lateral length will show slightly worse results than displayed here.
We are having some issues with the blog comments at the moment. Your post may be inadvertently held for moderation, and when your comment contains an attachment, it fails to get published.
Please bear with us while we resolve this.
In the meantime, you can always contact us, as we’ll be happy to manually add any attachments or get your comment up.
Thank you for your patience!
Enno
Mike, Brook
1 down. 2 to go.