North Dakota – update through July 2019

These interactive presentations contain the latest oil & gas production data from all 15,046 horizontal wells in North Dakota that started production from 2005 onward, through July.

Oil production in North Dakota further increased in July, to just over 1.4 million bo/d. Gas production also set a new record, at 3 Bcf/d. Completion activity remained as high as in June, with almost 140 wells coming online.

All the production profiles of these wells are shown in the “Well quality” tab. The thickness of each curve is related to the well count of that year. From the bottom plot you can learn that since 2012, significant improvements were made in well productivity. But from 2017 onward these gains have slowed, and preliminary data shows that the 2019 performance is on par with last year.

About 35% of all these wells, or just over 5,000, are now producing at a rate below 25 bo/d (see the bottom plot in the “Well status” tab).

Of the top 5 operators, only Hess and Marathon set new output records in the last 6 months (“Top operators”).

The ‘Advanced Insights’ presentation is displayed below:

This “Ultimate recovery” overview shows how all these horizontal wells are heading towards their ultimate recovery, with wells grouped by the year in which production started.

It shows that the 163 horizontal wells that began production in 2007 have so far recovered 220 thousand barrels of oil, and they are still flowing at 23 bo/d, on average. The 972 wells that began 10 years later (2017) have each almost recovered the same amount (208 thousand bbl), but they are still flowing at an average rate of 157 bo/d.

Scott Lapierre posted an article last week on LinkedIn, in which he shared his analysis on decline rates in relationship with changing gas-to-oil ratios (GORs), for which he also used our subscription service: On the Nature and Character of the Widespread Oil Production Shortfalls.

While we don’t see the effect strongly on an aggregate basis, in several basins, including here in the Bakken we do find cases that support his view. In the past I’ve already highlighted the performance of wells and GORs in the Parshall and Sanish fields.

Today, I wanted to share this screenshot, in which we can see the performance and GORs of wells in the Banks field, which was the most productive field in North Dakota in March and April this year (over 80 thousand bo/d, higher than the Parshall or Sanish ever was), but which saw a steep decline in recent months (it’s at 60 thousand bo/d in July).


Well performance and GORs in the Banks field (ND)

On the left you find the location of the 193 wells that began production in the years 2015-2018. The color of the well indicates the GOR in the most recent month (July). On the right the performance and GORs of these wells can be found. Note the recent increase in GOR for wells that began in 2017 & 2018. These recent wells also appear to track a similar or lower EUR than earlier wells, despite peaking far higher. It looks slightly worse once you group these wells by quarter, instead of year (possible in this dashboard).

This image was taken from our ShaleProfile Analytics service (Professional).

We now subscribe to the Premium service of the NDIC. This allows us to have slightly more accurate data for North Dakota, but it also ensures that we always have the latest production data in our subscription services.

We have started a collaboration with Lower48 Analytics, which offers a financial platform for oil & gas asset management. It will now be supported with our data platform: ShaleProfile collaborates with Lower48 Analytics, a financial platform for shale oil & gas asset management.

This Thursday September 19th, we are happy to host our first webinar, where we’ll address the topic of Terminal Decline Rates in all the major tight oil & gas basins. It will take place at 10 am CT and last about 30 minutes. Make sure to save your spot to ask all your questions!  Free registration link:

Early next week, we will have a post on gas production in Pennsylvania, which also released July production data recently.

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 40 kbo/d) is produced from conventional vertical wells.



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.


  • Sjoerd says:

    The Grail field is an interesting case study. It has been very productive and drilled intensively by QEP. They stopped drilling in Q3 2017 and there’s a suggestion as to why in the ultimate recovery view and on the well map:

    Grail is at 10.3 wells per 1280 acre DSU. Interestingly, the fields with the highest production are all closer to 10 than to 0 and have accelerated drilling over the past few years (which obviously contributes to them having the highest production, besides being in the core and being relatively large fields).

    Banks is at 7.0 wells/DSU and currently has 6 rigs on it. Assuming 25 wells/rig/year and continued drilling there is just over a year left before they reach 10/DSU.

    Reunion Bay is at 6.5 wells/DSU. Antelope is at 7.3 wells/DSU. Blue Buttes is at 8.9 wells/DSU. Corral Creek is at 7.0 wells/DSU. Sanish is slightly different as it has a lot of shorter wells on it.

    1. brookpe says:

      Very interesting Sjoerd. If the pay were 40′ thick and 6% porosity, 128 acres would be right at 2.4MMbarrels Pore Volume. So essentially the exchange of essentially 15% oil saturation for gas saturation underground would give you 350 Mbbls over that pore volume.

      1. Sjoerd says:

        Drainage as a % of original oil in place would indeed be very interesting to know. But I don’t know much about the geological side and probably hard to get good data on thickness, porosity, organic content, etc for different areas? Like nuassembly says below, they have drilled at least two layers in this area, so at least 250 acres per well per layer.

        It looks like Grail is in the highly productive Nesson Anticline region. It’s probably fair to say that the economics on this kind of spacing wouldn’t be the same for your average Bakken area.

        Between their strong Bakken wells and their Midland wells they have been significantly free cash flow negative for at least the last four years, with no real production growth to show for it. They are lucky they had some other assets they could sell.

  • nuassembly says:

    The 10 wells per DSU include the lower Three Forks according to the data plots here.
    In 2015 they drilled 20 in MB and 20 in TF, and surprisingly they only drilled in TF with 2 in 2011 and 9 in 2012, and the 2 TF wells in 2011 are the best and rest TF 2012 wells are the second to the best in all the wells drilled so far, doing 500Mbbls and 400Mbbls.
    Don’t know what happened in 2016 and 2017, the decline just accelerated like crazy and shows QEP drilled to a wall in both MB and TF.

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