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 88,617 horizontal wells in 10 US states. Cumulative oil and gas production from these wells reached 8.6 Gbo and 94.2 Tcf. The latest data for Ohio, which just released Q1 production figures, is also included.
With the surge in drilling and completion activity since early 2017 both oil and gas production from these horizontal wells reached new records in recent months, at over 5 million bo/d and 50 Bcf/d. Current production is heavily dependent on recent completions, as the decline rates are high; for example, oil production from wells that started producing before 2015 is contributing just 23% of current production, as shown by the top of the dark green area in the above graph.
Between the basins there are major differences, with some setting records each month (Permian, Appalachia, Niobrara), while others have not fully recovered yet (Eagle Ford, Haynesville), and a few appear to be in terminal decline (Barnett, Granite Wash).
The major underlying reason for these differences is changing well productivity, which can be analyzed in the ‘Well quality’ tab. Note that the oily basins have been preselected in the ‘Basin’ filter, which you can manually adjust.
The ‘Advanced Insights’ presentation is displayed below:
This “Ultimate recovery” overview shows the relationship between cumulative production, and production rates, over time. Also here the oil basins are preselected, and wells are grouped by the year in which production started.
The major increase in initial well performance in the past 2 years is clearly visible here.
Later this week I will have a new post on North Dakota, which just released May production.
Next week we will be present at the URTeC in Houston, so if you like to know more about our upcoming analytics services, come visit our booth.
Production data is subject to revisions. For these presentations, I used data gathered from the sources listed below.
- FracFocus.org
- Colorado Oil & Gas Conservation Commission
- Louisiana Department of Natural Resources. Similar as in Texas, lease/unit production is allocated over wells in order to estimate their individual production histories.
- Montana Board of Oil and Gas
- New Mexico Oil Conservation Commission
- North Dakota Department of Natural Resources
- Ohio Department of Natural Resources
- Pennsylvania Department of Environmental Protection
- Texas Railroad Commission. Individual well production is estimated through the allocation of lease production data over the wells in a lease, and from pending lease production data.
- West Virginia Department of Environmental Protection
- West Virginia Geological & Economical Survey
- Wyoming Oil & Gas Conservation Commission
====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 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.
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24 Comments
If you really look hard at this graph all areas all sands (oil basins only). It is actually quite amazing. Have results gotten better over time?
Jim,
Indeed, I can imagine that some operators wish they got more results like those early bakken wells. See EOG for example:
Enno,
It’s amazing how EOG’s wells performances vary so much over the years in Bakken.
The wells started before 2006-2008 look more like conventional wells that starts relatively low and declines much slower than any uncoventionals. The 2013 wells started highest and declines also much slower. But, then the 2009-2012 and also 2014-2017 are just falling into regular unconventionals, and even worse than majors like CLR and COP, MRO.
First parshall was under-drilled(maybe) then it was over-drilled.
I would suggest that the 2013 drill sites were carefully selected on the basis of a comparison between individual well recoveries and volumetric estimates to high grade undrained areas.
The paper below published in 2011 by Colorado School of Mines actually did EOGs work for them.
https://www.onepetro.org/conference-paper/SPE-149471-MS
Most of the earlier EOG Parshall wells were in the 5,000′ lateral length range as the DSUs were still one square mile in North Dakota back then.
The Gis map from North Dakota’s DMR site offers a pretty good visual of both the length and configuration of these wells.
FWIW, at the recent Williston Basin Petroleum Conference, highly regarded Liberty Resources gave a presentation on their Bakken EOR project which is just getting underway.
Using injectors for gas, they are hoping for a high bump in ultimate recovery.
A lot of people will be watching the results.
For those following the Appalachian Basin, Ohio’s long over due first quarter report was just released, along with Pennsylvania’s May results.
Ohio’s exit rate surpassed 6 Bcfd with quarterly average 5.9 Bcfd.
Almost 170 wells produced over 1 Bcf for the quarter with a well from Eclipse showing just under 3 billion cubic feet (@2.9).
As the 2012 USGS Utica assessment projected only .6 (point six) Bcf/well EUR over 30 years, the next evaluation will be much higher.
Marcellus has the McGovern 6 surpassing the 10 Bcf mark in 10 months (307 days) with Cabot’s Howell 8 not far behind at 9.78 Bcf in 311 days online.
The 2011 USGS Marcellus assessment pegged the mean EUR at 1.16 Bcf/well over its expected lifetime.
Big upward revisions will come when the new assessments are released.
Coffeeguy,
Ohio’s latest numbers are also in this presentation. Very interesting to see the difference in production profiles between Ohio and Pennsylvania.
Pennsylvania: lower initial production, but a more hyperbolic decline
Ohio: far higher initial production, but a more exponential decline?
By the way, Liberty Resources is one of those operators who might like to see some of those earlier results back again 🙂
23% of current oil production from wells with first production prior to 1/1/2016!
The CAPEX just never ends in these shale basins.
I am still wondering if inflated EUR’s are leading to understatement of cost depletion, and thus overstatement of GAAP EPS. Anyone looked more closely into this issue since it was discussed a couple of years ago? Also, I still wonder if the large write downs taken in 2015 and 2016 are a significant reason why several shale companies are reporting positive GAAP EPS in 2018?
Would love to see some of the Federal tax returns for these companies from 2015-2017.
Shallow Sand,
Interesting questions indeed. Just a minor correction:
> with first production prior to 1/1/2016!
Should be 1/1/2015
that’s a minor correction that shed light from end of tunnel for shalers, Enno!
Shallow sand,
I’ve been wondering the same thing over the past year or so. Though I’m not an expert on the relevant accounting, I’ve been playing around with the numbers. It’s generally tough to compare production and the books of the companies because most of the companies are spread over different areas (not all of which are covered here), gas/oil depleting at different rates, etc.
However, two companies I’ve been looking at have been Whiting and Carrizo. The former is mostly Bakken and the latter is (or was, until recently) mostly EF. Whiting’s books as of Q1 show PP&E of 11,608mln, almost all of which relates to oil & gas properties. Accumulated depreciation, depletion and amort is 4,430mln. That’s DD&A of 38%. If you look at their ultimate recovery graphs here, extrapolate and divide the production so far by the extrapolated totals, everything pre-2017 seems to be >2/3 in terms of production. Since then, their well count has increased by less than 10%, which wouldn’t explain the difference, especially since these new wells have been partially depleted as well.
Obviously this is not a very precise approach and I could be missing something on the accounting side, but my intuition says the gap is very large.
Cheers,
Sjoerd
Enno, great intel, thanks!
Wondering how many wells are not making the cut, i.e. effect of “survival bias”. Total number of well should be much larger, isn’t it? Does it mean many wells never produced long enough to be reported?
You’re welcome Daniel!
I only include wells that started after a certain year, e.g. 2005 for North Dakota, and around 2008-10 for most other states. However, for all these wells there is no survival bias: once production has started, I keep reporting them, even if they are no longer reported by the state agencies (I set them to 0 production).
For all the curves shown here, the number of wells that were part of it are available in the tooltips (this is also represented by the thickness of the curves), so you can easily verify that no wells drop out of the equation.
Thanks, Enno.
Yes, I’ve noticed number of wells on the report is a) not changing with time and b) small.
Do you have a feel what happened to other wells? Industry been drilling 10-20K Hz wells/year.
Good set of slides and reference to SPE paper on type curves: https://www.spe-qld.org/useruploads/files/20171108_speq_dl_presentation_-_randy_freeborn_-_type_wells_2017_11_08.pdf
Jim,
Is it possible that, regardless of fractions size etc, maybe the size of “the tank” doesn’t vary? Maybe it is just draining quicker (ie – higher IP, Higher decline)? I can see a real argument to support this from a fluid mobility perspective.
Ian
Ian-
Your comment about fluid mobility limitation is a good one- The relative permeability to oil will be more dramatically impeded one would think with high initial drawdown.
There is a lot of talk about well length, stages, sand load, etc, but I rarely hear anyone talk about spacing per stage. The initial Bakken wells were a mile long with 10 stages say. So, you had essentially 10 vertical wells spaced 528′ apart. If you say cut that down to 200′ in between wells, would you expect greater or lesser interference between wells over time?
Jim,
Good points – I don’t think anybody even has looked at interference. One of the other points I wanted to make is: great, you can fracture a hundreds/thouands of feet from the sand face (shale face?) but can you pull a droplet of oil, often through a water wet system, with limited drawdown/lift capacity, to the wellbore?
The closer the Physics is looked at, the easier it is to understand why more, or larger fractures, are not leading to higher EUR
Thank You
I was drilling a well last week a couple of hours west of Houston along Interstate 10 and my friend Enno Peters was gracious enough to drive over after URTeC to meet my wife and I on location and see some ‘real’ oilfield. We were RD the casing crew and getting ready to RU BJ to cement the long string so his timing was perfect. It was a balmy 103F on location but Enno handled it like a real hand.
He also took the time to demonstrate his new analytical portals on shaleprofile.com and I was absolutely amazed. From lateral lengths to proppant loading, to water use to GOR, etc. etc.; it is incredible data, all right there at one’s fingertips. Roughneck-easy to use, with beautiful graphics… and more than reasonably priced. I don’t think the shale oil industry will like it very much, from what I can tell (the truth is sometimes painful), but anybody needing to make important financial decisions based on the future of the US shale oil industry, be it lenders, service companies, taxing authorities or midstream gatherers needing to decide whether to lay new pipe or not… if you want to see what is really happening in America’s shale basins, you NEED the new and greatly improved shaleprofile.com. I wish the knotheads making America’s current energy policies would get it.
Thank you, Enno !! Y’all come back now, hear?
Mike,
Good to see Enno, I met him in UrTEC and enjoyed his new portal and I have a booth next to his booth.
Wish there are now the same lucky oil men like Chuck Alcorn, or Ray Holifield, a couple of hours West of Houston!
https://www.texasmonthly.com/articles/new-oil-the-giddings-gamble/
Nuassembly,
Great to see you as well at the Urtec, and to hear your own background! Hope your booth was as busy as ours, as we had barely time to eat a sandwich. A good number of visitors knew the blog or remembered the posts on OilPro, and interest in the Analytics Portal was double our expectation.
Here is a link for those who would like to get more info on our Analytics Portal that we launched last week: ShaleProfile Analytics
Mike,
You’re too kind; I think I handled the weather for like 10 minutes, before retreating to the AC’ed room. No idea how you manage to even do actual work in those temperatures. But it was fantastic watching the operations, and having the chance to sit down with you!
Next time we’ll have Heineken as well. In the mean time, keep your production and posts up!
Enno,
have you thought about adding boe to product type? or too much hassle due to different calorific values ?
regards,
daniel
Daniel,
I typically think that boe is bad replacement for the separate oil & gas streams, as the boe answer is not enough to understand well performance. In discussions, I don’t get much disagreement about that, just that some say that others may need it.
I am therefore curious what you belief the added value for it would be.