North Dakota: Initial well productivity trending higher, will a rising Gas/Oil ratio negatively impact EURs?

(edited)

North Dakota – update through March 2018

This article contains still images from interactive dashboards available on the blog post. To follow the instructions detailed here, use the interactive dashboards. You can also explore the dashboards to uncover different insights and trends.

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This interactive presentation contains the latest oil & gas production data from all 13,341 horizontal wells in North Dakota that started production since 2005, through March 2018.

February oil production in North Dakota came in at 1,162 kbo/d, after a month-on-month drop of 1%.

The wells that started in 2018 show so far a similar production profile as the ones from the year before (see the ‘Well quality’ tab. You can click on the 2018 vintage in the color legend to highlight the related curves).

Oilprice_1805_Graph-01.png

In the final tab the performance of the 5 leading operators is shown. EOG, the largest US shale oil operator, hasn’t completed any new wells in North Dakota since October last year , and produced just 43 kbo/d in March, vs 70 kbo/d in June 2017.

Oilprice_1805_Graph-02.png

In the ‘Advanced Insights’ presentation displayed below, the “Ultimate recovery” overview shows how all these horizontal wells are heading towards their ultimate recovery, with wells grouped by the quarter in which production started.

Oilprice_1805_Graph-03.png

The far better early-life well productivity in newer wells is also visible in this basin.

But as the 9th tab shows (‘Gas oil ratio’), the gas/oil ratio is rising faster for wells than it used to be. There are concerns emerging that this leads to a loss in formation pressure, and therefore may steepen declines.

Oilprice_1805_Graph-04.png

There are already spots where this is visible. For example, in the 2 largest fields, Sanish & Parshall (see the 2nd tab ‘Cumulative production ranking’, where these 2 fields are at the top), well performance has steadily declined since 2007/2008, even though more recent wells started at rates pretty similar as before.

You can see this by choosing just these 2 fields in the ‘Fields’ selection (tip: click on ‘All’ to deselect all fields, and then search for these 2 fields), and selecting to show wells by the year, instead of the quarter in which production started; wells that started in these 2 fields in 2007/2008 recovered on average around 450 kbo before dropping to 50 bo/d, while this is just around 200 kbo for wells starting since 2014.

Oilprice_1805_Graph-05.png

Next week I plan to have new posts on the Haynesville, and the Marcellus.

For these presentations, I used data gathered from the following sources:

  • DMR of North Dakota
    These presentations only show the production from horizontal wells; a small amount (about 30 kbo/d)  is produced from conventional vertical wells.
  • FracFocus.org

Visit our blog to read the full post and use the interactive dashboards to gain more insight
https://shaleprofile.com/index.php/2018/05/17/north-dakota-update-through-march-2018/

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Twitter: @ShaleProfile
Linkedin: ShaleProfile
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Edited by shaleprofile
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Enno, very happy to see you made it over here to this Oil Price forum!  Thanks for accepting my invite : )

To those who don't know Enno or who are not familiar with his site  https://shaleprofile.com  please do have a read.  I've been a fan of Enno's research and wonderful interactive graphics for a long time.  Nothing else like it for O&G data on the internet.  

2 thumbs up, Enno 👍👍 and happy to have you on board here.

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Great to see you here Enno - we're working on a way to get the tableau graphs installed. 

In the meantime, welcome to the community!

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Thanks Enno.

One possible North Dakota Bakken scenario, which aligns with USGS mean estimate from April 2013 with TRR=10 Gb.

 

bak1805.gif

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Glad to see you here, Enno!

"Unconventional wisdom" suggest that there should be no increase in GOR  from microdarcy rock; I'm puzzled with it. My guess it happens because of interference between wells; possibly new fracs are hitting depleted areas on offset wells? Any reservoir engineers in the know here?

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Among all my Petroleum Engineering courses at the University of Oklahoma, I have never seen such high-quality data. How long did it take to create all these charts, Enno? Also, how'd learn how to do all this? If you do not mind me asking.

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Dennis, what on EARTH does this model you've provided have to do with Enno's comments regarding increasing GOR in the Bakken? Rising GOR in solution gas-driven rock like shale is serious stuff. It implies all kinds of things and NONE of them are good. I'd ask where you think the Bakken LTO industry is going to get $200 billion dollars to drill 20,000 more wells you lay out in your model but I suspect that answer would be based on hope for higher oil prices. The more relevant question is where are you going to put those 20,000 more wells? Sweet Spot Motel already has the No Vacancy sign up. Are you simply trying to find a way to recover USGS TRR estimates?

 

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Thank you all for your kind comments, and Tom of course for inviting me here!

Eric, glad you enjoy them! They took a bit of effort indeed, but I had a lot of fun doing so. We're now in the process of making even more interactive dashboards available, as a subscription service. My own background is in AI & designing information systems, and that together with an interest in these developments, and the nice feedback from many, caused that I put way too much time in this :-)

I still often learn from experts like all present here, and may sometimes miss the mark in which case I will happily accept any corrections!

 

 

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On 20. 05. 2018. at 11:40 AM, Mike Shellman said:

Dennis, what on EARTH does this model you've provided have to do with Enno's comments regarding increasing GOR in the Bakken? Rising GOR in solution gas-driven rock like shale is serious stuff. It implies all kinds of things and NONE of them are good. I'd ask where you think the Bakken LTO industry is going to get $200 billion dollars to drill 20,000 more wells you lay out in your model but I suspect that answer would be based on hope for higher oil prices. The more relevant question is where are you going to put those 20,000 more wells? Sweet Spot Motel already has the No Vacancy sign up. Are you simply trying to find a way to recover USGS TRR estimates?

 

This is great stuff. But for those of us who aren't geologists/engineers or oil and gas experts per se, can you explain in more detail, for the layman, the implications the rising GOR will have in Bakken? 

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(edited)

Shale (mudstone), or shaley carbonates in the Permian, is for the most part, solution gas, or depletion driven rock; http://petrowiki.org/Solution_gas_drive_reservoirs.  At various stages in the well's life, and some dependent on how the well is managed, induced energy from the frac poops out and the well transitions to solution gas drive and flows for a while longer. Then  the well stops flowing and is put on artificial lift. Eventually the well reaches bubble point, free gas breaks out the fluid phase and the gas to oil ratio increases. Bubble point and increasing GOR is indicative of reservoir depletion, or in the case of shale wells, "container" depletion, the container being the extent to which the well was frac'ed, and can be effectively drained. Downspacing in core areas creates more containers, the containers start communicating with each other and ultimately liquid recovery is reduced from lack of bottom hole pressure and/or gas drive. My apologies to petroleum engineers who can explain it better. Here is a good, simple article from a geologist: https://www.forbes.com/sites/arthurberman/2017/03/01/the-beginning-of-the-end-for-the-bakken-shale-play/#7754fdf41487 and here are several from a petroleum engineer: https://www.linkedin.com/pulse/bubble-point-death-pxd-oil-mix-challenge-part-2-scott-lapierre/

The problem with the shale oil phenomena is two fold: can it pay its debt back, or will it be required to pay its debt back, and can it continue to drill marginally profitable wells on properly managed credit? Or are it's sweet spots, it's core areas that it has relied on for so long going to poop plum out. Personally, in the Bakken and Eagle Ford they are already pooping out. The same will eventually occur in the Permian. Moving off core areas into (EIA) Tier II areas will cost MORE money, productivity will likely be less, and profits even worse. Increasing GOR, when there is no market for associated gas, negatively affects economics.

Conventional oil did not grow on trees as 150 years of history clearly shows us; neither does shale oil grow on trees. Its reserves, drillable locations and promises for the future have all been grossly exaggerated. 

Depletion never takes a day off. Its the nature of the exploration and production exercise. Trying to predict the role shale oil will have in our future based entirely on supply/demand theories is a mistake.

   

Edited by Mike Shellman
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