Playing With The Numbers -- A Back-Of-The Envelope Exercise -- Not Ready For Prime time

For those who like to play with numbers, this is kind of interesting, and kind of fun.

First, here's the link from which I'm operating, an interactive UND-EERC map at http://www.undeerc.org/bakken/dss/. The data apparently is current as of 2012 -- only six years old. LOL.

I then looked at two fields, the Charleson and the Antelope, two very good fields in the Bakken, and fairly underdeveloped back in 2012.

It's hard to say how many wells are actually draining each field, but suffice it to say there are about 40 wells in the Charleson field, and no more than 40 wells in the Antelope field, but for "ease," I will consider 40 wells in each field. The two fields almost touch each other: Charleson, smaller, is to the northwest of the larger Antelope field. I would assume the original oil in place (OOIP) is about the same on a "per-mineral-acre" basis.

Original oil in place (OOIP) in each field (source of data not stated):

• Charleson field: 136,552, 938 bbls of oil
• Antelope field: 805,670,835 bbls of oil

It appears that oil companies were recovering somewhere between 1% and 15% of the OOIP through primary production back in 2012. Early in the boom, 2007 - 2010, the estimate was probably 1 - 3% recovery through primary production. Later in the boom, by 2012 or so, it was publicly stated that primary recovery was about 7% but it might have been as high as 12%.

Some are opining that primary recovery might eventually get to 20% in the near term and some suggest as high as 50% in the long term. Don't quote me on any of this; it's just my perception and what I seem to recall. My "recall" is often very, very poor.

With regard to EURs, early in the boom, in this area, EURs were probably estimated at about 500,000 bbls. Since then, EURs have greatly increased.

But for argument's sake, we will suggest that EURs in this area were 500,000 bbls/well back in 2012. By the way, at this time, 2012, most of the wells in the Charleson were Three Forks well (blue in the graphic); in the Antelope, almost all of the wells were middle Bakken wells (red in the graphic).

So, let's run some numbers.

I think one can get any number one wants, but this is what I did.

Charleson:

• 40 wells
• 40 * 500,000 = 20 million bbls EUR
• 20 million / 136,552,938 = 15% primary production (estimate)

Antelope:

• 40 wells
• 40*500,000 - 20 million bbls EUR
• 20 million / 805,670,835 = 2.5% primary production (estimate)

Some observations:

• primary production estimate in Antelope is based on 40 wells; it appears there are clearly less than 40 wells in the Antelope at this time (in other words,that 2.5% primary production might actually be less)
• there's no way that two fields right next to each other should have such disparate primary production estimates
• obviously a lot more wells are going to go in than just the current 40

Possibilities:

• I'm misreading something (most likely possibility)
• 15% primary production seems about double what we were being told back in the early boom
• 2.5% (and possibly lower) primary production is ridiculously low, especially considering these were mostly middle Bakken wells
• the estimated OOIPs are ridiculously low (that's my hunch)

Disclaimer: whenever I do these back-of-the-envelope exercise I make amateur mistakes. But that's fine. That's how I learn -- if folks tell me where I'm wrong. But it gives me a starting point. Have fun doing your own calculations. It's an open book exercise.

I can't wait to see the results of the 2020 USGS survey. I personally think the 2020 USGS survey will, at a minimum, double the reserves estimated in the 2013 USGS survey. We could possibly see a tripling of the reserves. Much of the outcome will depend on the price of oil when they accomplish the survey. The lower benches of the Three Forks were not considered in the 2013 USGS survey.

Status Of Natural Gas Processing Plants In North Dakota -- June 16, 2018

Lynn Helms mentioned that flaring in the Bakken has gotten worse. Some of it is due to temporary "glitches," but mostly it is due to "over-production."

The Director, NDIC, mentioned that five new natural gas processing plants were under construction or in development stage, and one plant's expansion project should be completed by the end of the year (2018).

Here's the current line-up:

Pending USGS Survey Of The Bakken / Three Forks -- June 16, 2018

Updates

June 16, 2018: the next USGS survey of the Bakken/Three Forks was scheduled for 2020. North Dakota congressional representatives successfully lobbied the USGS to begin the survey sooner. That was announced on December 11, 2017. This suggests to me that the USGS should begin the new survey not later than by the end of 2018. Let's hope.

June 16, 2018: "baseline." IP30 data and well metrics update -- economics of the average well -- from SeekingAlpha. 

Summary:

• IP30 trends (oil) are shown for 17 Bakken producers
• additional well metrics and info is provided for major producers
• early 2017 data are discussed
• required WTI prices for certain IRR and cash flow levels are specified.

IP30: average daily oil production of a well in its peak production month. It's usually express in bopd. Oil includes condensate. The IP30 month follow the completion month with a lag of one to severl months -- so, the correlation between both numbers isn't perfect.

The official NDIC (North Dakota Industrial Commission) database lists 71 operators having drilled horizontal wells in North Dakota's Bakken. The table below shows average IP30 values and the associated number of wells for all active companies which had at least 40 IP30 wells since the beginning of 2014 and 10 wells with IP30 in 2016. They represent 97% of all horizontal wells.

Data for seventeen producers:

Oil & Gas Lease Results -- North Dakota -- May, 2018

Link here for May, 2018 (on-line).

Billings

• two tracts, 80 mineral acres each
• bonus: $2.00 / acre
• yes, you have have bought 160 mineral acres in the Bakken for $320

Burke

• twelve tracts, from very small 0.03 acres to 160 acres
• very small bonuses; largest $151/mineral acre

Dunn:

• one tract, 80 acres; $26 / mineral acre

Golden Valley

• fourteen tracts; several 160-acre tracts; average around $20 / mineral acre
• many winning Northern Energy Corporation bids

McKenzie

• ten tracts, most of them 160-acre tracts
• from $9 / mineral acre to $218 / mineral acre
• many winning Northern Energy Corporation bids

Mountrail

• ten tracts
• various sizes; many 80-acre- and 160-acre tracts
• from $2.00 / mineral acre to $1,001 / mineral acre (I imagine that individual that bid $1,00 / mineral acre is really, really upset)
• many winning Northern Energy Corporation bids

Stark

• five tracts, all except one, 80 acres; the fifth, 75.41 acres
• $12 / mineral acre to $21 / mineral acre
• many winning Northern Energy Corporation bids

Is The Bakken Upside Capped? Another Look, Six Months Later -- June 16, 2018

Re-posting:

From The Bismarck Tribune:

North Dakota oil production jumped 5.4 percent in April to more than 1.2 million barrels per day, coming in just shy of the state’s record.

Director of Mineral Resources Lynn Helms called it a big surprise to see production levels within 2,500 barrels of the all-time high of nearly 1.23 million barrels per day.

“We were not expecting that kind of a surge until late May, early June,” Helms said Friday while discussing the preliminary figures.

Natural gas production increased 7.4 percent in April, setting another record at more than 2.24 billion cubic feet per day.

Do you remember this absurd BTU Analytics article? I'm not sure I ever posted the link; the article was simply too absurd. Or maybe I did post the link before but I can't find it now. Whatever. From the linked absurdity:

The recent announcement of Oasis Petroleum’s Delaware Basin acquisition marks another major Bakken producer re-positioning to focus its growth capital outside the Williston Basin.

What do these shifts signal about the future of the Williston Basin?

By choosing to look for growth elsewhere, Oasis answered two related questions: how it plans to increase its inventory of ‘premium’ well locations as well as where the company views its best opportunity for low-cost production growth.

Because one of the largest Bakken pure plays chose this route, does it mean that Bakken upside is capped?

One concern mentioned by Bakken naysayers is that ‘premium’ inventory is running low, particularly compared to the opportunity set in other basins. BTU developed a new, well inventory model using the actual location of previously drilled wells, along with spacing, lateral and drainage assumptions to calculate remaining locations in each major shale basin, as featured in the most recent E&P Positioning Report.

The chart below shows the remaining locations in the Bakken by breakeven band compared to BTU’s forecast for well completions in the basin. In addition to having less than 250 remaining locations that breakeven below $30/bbl wellhead, more than 70% of locations that breakeven below $50 will be exhausted over the next five years.

Screenshots from the article:

The DAPL May Have Saved The Bakken -- June 16, 2018

If one considers what happened between 2014 and 2016, both nationally and internationally, one can make a case that the DAPL may have saved the Bakken, no thanks to Standing Rock.

Link here.

Almost without notice, an important anniversary came and passed recently.

On Friday, June 1, the Dakota Access Pipeline marked one year since the pipeline successfully began transporting Bakken crude from near Stanley, North Dakota to Patoka, Illinois.

How could we miss the anniversary for a pipeline that sparked intense protests and the world’s attention for nearly an entire year prior to operation?

The answer is relatively simple. Pipelines, despite the propaganda against them, offer relatively uneventful daily operations. They quietly move materials like crude, natural gas, water, CO2 and refined products across the United States with only rare  significant issues. In fact, 99.999 percent of petroleum products get to their destination without incident and the pipeline industry has proven its commitment to making that number even better with a decline in incidents of over 50 percent since 1999.

Re-posting:

From The Bismarck Tribune:

North Dakota oil production jumped 5.4 percent in April to more than 1.2 million barrels per day, coming in just shy of the state’s record.

Director of Mineral Resources Lynn Helms called it a big surprise to see production levels within 2,500 barrels of the all-time high of nearly 1.23 million barrels per day.

“We were not expecting that kind of a surge until late May, early June,” Helms said Friday while discussing the preliminary figures.

Natural gas production increased 7.4 percent in April, setting another record at more than 2.24 billion cubic feet per day.

And then this, link here:

 For more on the Legacy Fund, click on the "Legacy Fund" tag at the bottom of the blog.

Bakken Well Vs Permian Well: Almost 3X More Crude Oil Per Well -- June 16, 2018

Link here.

The numbers speak for themselves. No comments necessary. For both oil and natural gas, the Bakken is beating the Permian.

Oil: 3x

Natural gas: close but about 1.5:1.