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 from all 12409 horizontal wells in North Dakota that started production since 2005, through April 2017.
Oil production in April rose with 2.5% over the previous month (1,051 kbo/d vs 1,026 kbo/d) . This was also the first time since almost 2 years that production was higher than a year earlier. Gas production increased with more than 5% to 1.8 Bcf/d, setting a new record in North Dakota. In April 68 new wells started production, vs 56 in March.
In the “Well quality” tab, the production profiles of all these wells can be seen. This time, I’ve preselected a linear axis scale, instead of semi-logarithmic, in order to highlight how initial production rates have increased in recent years. The initial production peaks have been pushed higher, and far more oil is recovered in the first year on production. The declines after the peak are also sharper, and after about 2 years, the impact of these improvements on the production rates has mostly dissipated.
The last tab (“Top operators”) shows the total production and location of the 5 largest operators. EOG, while very strong in the Eagle Ford, is at the bottom of this list in the Bakken. It has increased production in recent months, but this was all due to the completion of already drilled wells. It hasn’t drilled any new wells in 2017 so far (this can be seen in the “Well status” overview, if you select EOG as the operator).
The ‘Advanced Insights’ presentation is displayed below:
This “Ultimate recovery” overview shows how all these horizontal wells are heading towards their ultimate oil or gas recovery.
Since the 2nd half of 2015, fewer wells are started (shown by the thinner lines, and in the tooltips), but the average initial performance has gone up.
The last two tabs in the presentation show how both the gas / oil ratio, and the water / oil ratio, are slowly moving higher.
By Friday I expect to have another post on all covered states in the US. Next week I’ll have another close look at the Marcellus & Utica.
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.
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.
Do you have a rough EUR estimate for the average Bakken/Three Forks well in North Dakota?
I have estimated about 320 to 360 kb with an assumed economic limit of 10 barrels per day (oil only), base on the data you present here. The NDIC presents a typical well profile (Sept 2016 presentation) that has about 963 kb over 45 years roughly 2.5 times my high estimate. The slide claims this is 25% above the 2014 average well, so that would be 770 kb in 2014 (my estimate for that year is 330-335 kb).
Your charts seem to point towards about 300-400 kb from 2009 to 2015, or so it appears to me.
North Dakota have a municipal bond sale coming up?
Seems to have worked for everybody else thus far.
I typically don’t work with EURs, and am not so interested in them. It depends on many factors that are, to me at least, unknowable, such as future oil & gas prices, where the economic limit is, and what operators will do to keep wells alive.
I make an exception in the Projecting posts, of which you find the latest here (see the 3rd tab) : https://shaleprofile.com/2017/02/28/projecting-us-shale-oil-production-after-june-2016/
In my view, it’s more interesting from an economic point of view, what wells do until they reach a rate of about 20-30 bo/d. There is already quite some data on this in several basins.
Whenever I want to get an idea on where wells are headed, I look at the ultimate recovery overview, and group wells by the month in which they started (and select the formations/fields/operators that I am interested in). It gives a pretty good indication of the possible range in my opinion.
Actually, Bakken’s EURs given by E&P companies/government are closest to reality, like shown here by Shaleprofile.com and your observation. The difference is about 50%~150% times. Other basins like Eagle Ford and Permian could have over 200% times up to 400% times difference easily.
“It’s discouraging to think how many people are shocked by honesty and how few by deceit.”
― Noël Coward, Blithe Spirit
I guess Enno is not interested, maybe you have an opinion on North Dakota Bakken/Three Forks EUR,
does 300 to 350 kb of C+C (oil) seem reasonable for an EUR?
Yes, Dennis, I do. Remember the discussion we had about DCA of tight shale oil wells where there are actually two flow regimes to consider? Typically shale oil EUR’s are determined based on IP30, during frac-induced transient flow. The flow from that well transitions in to radial type flow, I don’t know, within 30-36 months? Mr. Liu has described that far better than I can in the Permian thread and it is definitely worth reading. In a tight rock it is wrong to assume the well will drain, or behave, the same way thru its life cycle. Bigger IP30’s (minutes?) create enormous BOE EUR’s that are simply not true. The folks creating those EUR’s, in which P1 reserves are booked as assets, know that. The SEC allows them to do it anyway. We are going to soon find out America does not have 1/3rd the unconventional shale oil reserves it has been led to believe.
Does 300 to 350 kb EUR20year at least seem more rrasonable than NDIC EUR. 30 YEAR 870 KB?
Dennis 300-350K BO sounds far more reasonable than 870 over 30 years, yes. I am unclear how gas expansion shale “containers” will deplete past year 10-12; 30 years is a big stretch to me.
I usually assume exponential decline at 8 to 10% per year after year 12 to 15 (when the hyperbolic gets to about 9% or so I assume exponential decline beyond that point.)
Obviously this is a guess, your guess would be much better than mine based on many years actually drilling and producing wells.
Thanks though, I realize the EUR could be considerably less than my guesstimate, the fact is I do not know.
Yeah, “We are going to soon find out America does not have 1/3rd the unconventional shale oil reserves it has been led to believe.” — that’s true, even if price goes to $100
I agree the EIA estimates are much too high. The USGS estimates may not be too bad if oil prices are high enough ($100/b or more). I imagine we will produce at least to the level of the USGS F95 estimates for undiscovered oil plus cumulative output and proved reserves.