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 14,948 horizontal wells in North Dakota that started production from 2005 onward, through June.
Oil production in North Dakota set a new record in June, at 1.425 million bo/d. In the first half of this year, 565 horizontal wells were brought online, 10% more than in the same period last year. Completion activity in June was high, with 135 wells put on production.
The production profiles of all these wells can be found in the “Well quality” overview, where they are averaged and displayed by year. The wells that started production this year are so far tracking a similar performance as those from last year.
Hess just overtook Marathon as the 2nd largest producer, well behind Continental Resources (see “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.
As you can see, the 2018 vintage has had the best start so far, with a recovery of 120 thousand barrels of oil in the first 7 months, on average.
But if you look at it in more detail, by grouping the wells by quarter, the picture becomes murkier. It shows that well productivity did not really improve any more since 2017 Q3, as the wells that started in the beginning of that year dragged the average performance down.
Furthermore, laterals in 2008-2010 were on average about 20% shorter than in more recent years. Normalize for that and those early wells are on a path to outperform the newer wells, as you can see below (despite having a worse start!).
This image was taken from our ShaleProfile Analytics service (Professional).
Another screenshot I want to share from our service shows the updated “Well status” dashboard. The new version allows you to answer many kinds of questions related to well count, for example:
- The number of producing wells by operator in a certain region
- The number of wells that have fallen below a given production level
- The DUC count by spud year
The following image answers this last question, for all the DUCs that have been spud in North Dakota since 2015.
It reveals how the DUC count has evolved over the past couple of years. Of the 767 DUCs in June, that were spud since 2015, only 37 were drilled in 2015 and 2016. The map shows the exact location of these DUCs.
If you have other questions of this kind, simply request a demo or a free trial.
Early next week we will have a post on gas production in Pennsylvania, which also released June production data recently, followed by updates on the Permian and the Eagle Ford.
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.
- FracFocus.org
====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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6 Comments
Fantastic insights as always. Wells today, adjusted for laterals, are similar to the ones completed in 2010… To me it seems like a battle between geology and technology. Geology getting worse, technology better. Makes sense. You drill the hot spots first, which is obviously finite, then you venture into tier 2 and 3. I wonder when Permian will experience the same development.
These boys in North Dakota are getting busy blowing down those ducs. To keep a production rate of 1.4 million barrels a day it looks like they will have to complete around 1500 wells per year. They will be out of tier 1 wells in a couple of years from know at that rate.
If one were to view the 2008/9/10 vintage wells using the “well status” tab, the clear pattern of Nesson Anticline targeting, along with the Parshall/Sanish region should be readily apparent.
With Williston Basin production history going back ~70 years, operators were familiar with the region’s geology and hydrocarbon potential.
Mike Johnson leased 40,000 acres of the Parshall in 2005 for $3/acre, then sold the rights to EOG, which is why EOG dominates this area.
Back then, it was customary for laterals to be in the 5,000 foot range as the state’s Drilling Spacing Unit regulations had not yet doubled to 1,280 acre size.
Using the “ultimate recovery” tab, quarterly timeframes, for the years 2017 and 2018, one might get a glimpse of future Bakken production profiles.
Cutting edge completion practices employ what is being described as Extreme Limited Entry perforating.
Essentially, the hardware, pumping procedures, proppant placement (including micro proppants and diverters), micro seismic monitoring, and pre-planned stage placement are some of the components enabling operators to create and maintain a 1,500 to 2,000 psi ever-expanding “pressure bubble” within which WAY more of the pre-existing micro cracks open, are scoured, and propped.
Recovery rates are now claimed by some operators to be in the 20% range.
With the cost to drill/complete now about $5 1/2 million in the Bakken, tier 1 acreage is actually expanding significantly.
The biggest reason for current plateauing of Bakken oil production is the gas flaring issue, as Helms has repeatedly stated.
With proposed expansion of several takeaway pipelines and gas processing plants, record output is expected over the next 2 years … price dependent, as always.
Just did some math from the latest DPR, know it is unreliable but still:
North Dakota production in September 2018: 1,368 kb/d, legacy decline 63 kb/d
North Dakota production in September 2019: 1,436 kb/d, legacy decline 73 kb/d
Production increased by 5%, legacy decline by 16% in the last 12 months. This trend do not need to continue for long until Bakken plateaus…
The same is true for the other basins, but Bakken worst. Would think the opposite would happen, once production levels off, overall legacy decline goes down.
Any have an explanation?
@ Alex
Look at the last 18 months of wells and you will see that they make up almost 60 percent of all the bakken production. They wells will fall almost 70 percent from peak month 1 to 12 month later and it seems like the decline is accelerating. The Bakken has an overall 5 percent field decline per month if they keep completing wells at the rate they are completing. The only to well set that are increasing production on average is Month 1 new well and Month 2.
So if we assume a field decline per month of 5 percent on a base of 1.4 million barrels per day the month 1 and month 2 wells have to offset a monthly decline of around 2.1 million barrels per month.
If we assume Month 1 is like 2018 where the average well produce around 327 barrel of oil per day and Month 2 is like 662 barrels per month.
If they complete around 100 wells per month on average
100*327*30 days= 981,000 new barrels from Month 1 wells
100*(662-327)*30 days= 1,005,000 new barrels from Month 2 wells
That equals 1,986,000 new oil barrels per month
So as you can see 1,200 wells isn’t enough to maintain a field production of 1.4 million barrels of Bakken Field production
To understand how many wells are needed to support a certain production level, I simply estimate the average ultimate recovery, and divide the level by this number.
For example, suppose a 400k bbl average ultimate recovery, then 1.4 million bo/d / 400k = 3.5 wells per day are needed (=105 per month). This assumes that well productivity doesn’t change (highly unrealistic).
This simply follows from the idea that if every day you are adding 3.5 * 400k of new oil output potential, in the long run you will get to that level (1.4 million bo/d).
The initial rates and the shape of the decline do not matter in this calculation.