Saturday, October 12, 2019

Sorting Out A Mystery Of A BR Archer Well In Charlson Oil Field -- October 13, 2019

Disclaimer: in a long note like this there will be typographical and factual errors. There is at least one glaring error in an original source at the NDIC file report which I did not mention. I often see things that do not exist. I did not look at all wells in the immediate area of #26419. There may be other explanations for the huge jump in production in #26419. Regardless of the jump in production, the mom-and-pop mineral owners should be thrilled to see this huge jump in production (unless they hate paying more taxes to the IRS and the state of ND). It is very possible I made a very simple error/mistake that completely negates this entire post. I certainly could have mis-identified permit numbers, which I have done before. If so, that's fine; some reader will note it and bring it to my attention. I'm simply trying to better understand the Bakken. For all I know, it was simply a work-over rig or perhaps a small meteor strike.

Note: there's a similar mystery surrounding another Petro-Hunt in Charlson oil field, #26206. See this post.

The Original Post
Begun October 12, 2019
Completed October 13, 2019

Back on February 7, 2017, this post: "Possibly a record post-shut-in-production jump in the Bakken."

I was curious to see how these wells were doing two years later. Wow, what an adventure!

The well:
  • 26419, 2,904, BR, Archer 14-25TFH, Charlson, t2/14; cum 605K 8/19;
Note before going further:
  • this is one of several BR Archer wells
  • this BR Archer well was a Three Forks well drilled back in 2014; 
  • in five years, this well had produced over 600,000 bbls of oil
The first thing I noticed: the BR Archer wells were very, very good wells, but interestingly, some of the wells had been recently taken off line for a short period of time. That piqued my interest. I thought I was only going to be updating total production but immediately there was a puzzle. Why were these really good wells coming off line?

This was the biggest puzzle: the production profile of this well (#26419) did not make sense to me.

Look what happened to production between 3/18 and 9/18 (see portion of full production profile below). The huge jump in production meant that this well had to have been re-fracked.

But, neither FracFocus nor the NDIC file report showed any re-frack. Wow. I  had not seen this before. I had not seen such a huge jump in production in which there was not a re-frack. It just doesn't happen. Period. Dot.

Again, look at the jump in production -- an "old" well plateauing out to 5,000 bbls/month and then a huge jump in production -- as much as 26,000 bbls/month -- with no evidence of a re-frack. I had no idea what was going on. This did not make sense.


That's a huge jump, from 3,000 in 3/18 (only 18 days) to 26,000 in 10/18. The only thing that could explain this was a re-frack and yet there was no re-frack.

So, we had this jump from 3,000 bbls/month to 26,000 bbls/month and no evidence of a re-frack.

Obviously there had to have been a neighboring well that had been re-fracked.

So, let's go to the map.

Wow, that turned out to be a bummer.

Note that there is no neighboring well to the well in question (#26419) -- yes, some relatively close wells but they were all the same age or older than the well in question and thus they could not have been related to that huge jump in production.

Nothing made sense.

I zoomed in on the map.

I expanded the area of the map.

Again, nothing jumped out at me, unless one looked at those #338XX wells to the north of the index well, #26419. If so, this is something I had never seen before (or don't recall seeing, or missed) and I Iook at literally every well that's been drilled in the Bakken since 2007.

I zoomed in on the #338XX wells. It turned out that #33817, a section line well, was closest to the index well. See map above.

I looked at the history of #33817.

Wow! Eureka! Paydirt!

#33817 was fracked just before the huge jump in production for #26419 in 10/18.

Wow. I had not seen this before. The "child" well did not parallel the "parent" well for the entire length of the horizontals. The "child" well and the "parent" well aligned for only half of the horizontal.

All wells under discussion are two-mile-long laterals, but the index well and the neighboring #338XX wells only exist side-by-side for half their lengths (I note this on the map below: a heavy red line where the wells parallel each other and a thinner red line where they do not). 

Interestingly enough, the frack for #33817 was a relatively moderate frack. Production profile and frack data for #33817 at this post.

Relationship between #33817 and the index well:
  • #33817 and #26419 are 0.11 mile (580 feet) apart (horizontally).  
  • but note this:
    • #33817 is a middle Bakken well;
    • #26419 is a Three Forks well;
The next 338XX series well to the west is #33814. Relationship of #33814 to the index well:
  • #33814 is a Three Forks well; awesome!
  • it is located 0.2 mile (1056 feet) to the west of the index well
  • it was a very, very small frack, only 5.1 million lbs of sand (51 stages)
  • production profile for this well is here;
Okay, so there you have it. Data points, facts, comments, opinions:
  • #26419 is a Three Forks, first bench well, based on the name of the well, the permit and the Weatherford geological well report;
  • the well was completed in February, 2014; was a great well and then showed the typical Bakken decline, plateauing at a very respectable 5,000 bbls/month by 8/17
  • in early 2018, it was taken off line for five months
  • when it came back on line, production jumped from 5,000 bbls/month to an astounding 26,000 bbls/month, minimally better than the original frack, but the anticipated decline occurred more quickly; but it maintained high production for several months; full production profile is posted elsewhere (see link above)
  • the huge jump in production all but suggested this well had been fracked
  • neither FracFocus nor the file report showed any data to suggest the well had been refracked
    • it's been more than a year; the paperwork is "not in the mail"
  • at first glance there were no obvious neighboring, recently-fracked wells that could account for the huge jump in production
  • far to the north, and paralleling only half of the #26419 horizontal were #338XX series wells on a single pad that might have played a part
  • the geographic location and timing of the fracks of the #338XX series wells would account for the jump in production of #26419
  • #26419 is a Three Forks (that in itself is unusual, so early in the Bakken, to see a Three Forks well)
  • closest to this Three Forks well was a middle Bakken well (#33817) -- about 500 feet west
  • then, 1,000 feet to the west was another Three Forks well
  • fracks for both the #33817 and the #33814 were moderate and small fracks, respectively
  • I have not seen moderate and small fracks result in a neighboring well to have such a huge jump in production as we see in #26419
  • there is a third #338XX well on that pad fracked at the same time as the others (actually there are four)
  • there is a research paper out there, which I have linked elsewhere, published very early in the Bakken boom that suggested that the "parent-child uplift" phenomenon existed but it required three neighboring wells to be fracked simultaneously to affect a "parent" well 
  • it's hard to believe that a small frack in the same formation one thousand feet away caused a huge production jump in #26419
  • if not, then it was a middle Bakken well only 500 feet away that was also additive
One more thing:
  • the index well, #26419, an Archer well, is a BR-operated well (Burlington Resources/COP)
  • the #338XX pad to the west is a Petro-Hunt pad
  • think about that, especially from BR's viewpoint
  • these wells are in the Charlson oil field; that field is tracked here;
  • the Charlson oil field is one of the most interesting fields in the Bakken
  • it was "discovered" very early (see this post); it was this field that excited me as much as the Parshall oil field at the time;
  • the webmaster for a Bakken discussion group and another blogger first noted what an incredible field this was going to be
  • the Charlson is among the handful of early Bakken fields that stood out: Charlson, Parshall, Grail, Sanish
  • at one time, the Charlson had bragging rights to the most successful in the Bakken; I think that still holds true but do not quote me on that
  • since then there have been more record-setting wells in the Bakken
  • for how prolific this field seems to be, it is being drilled out very, very slowly, at least compared to a couple of other fields held by other operators
Disclaimer: in a long note like this there will be typographical and factual errors. There is at least one glaring error in an original source at the NDIC file report which I did not mention. I often see things that do not exist. I did not look at all wells in the immediate area of #26419. There may be other explanations for the huge jump in production. Regardless of the jump in production, the mom-and-pop mineral owners should be thrilled to see this huge jump in production (unless they hate paying more taxes to the IRS and the state of ND). It is very possible I made a very simple error/mistake that completely negates this entire post. I certainly could have mis-identified permit numbers, which I have done before. If so, that's fine; some reader will note it and bring it to my attention. I'm simply trying to better understand the Bakken. For all I know, it was simply a work-over rig or perhaps a small meteor strike.

US Shale Update -- Forbes -- October 12, 2019

This is just a "fun" article to read, a typical Forbes article. I didn't read it closely. But, for me, it looks like a "feel-good" article.

Link here to Forbes.

The problem I'm having is this. This article was published October 3, 2019. Should the writer be considered a candidate for the Geico Rock Award for 2019?

This is the headline: Texas, North Dakota, and New Mexico Leading the US Shale Oil Revolution.

I hate to do that -- nominating the writer for the GRA-2019 -- with a "feel-good" article about the Bakken, but, heaven's sake -- seriously? That headline? Where has the writer been? His defense -- he probably did not have anything to do with the headline. I'll give the Forbes editor the nomination.

While I'm sorting that out, these are incredible statistics from the article:
  • US crude oil production will steadily rise from 13.1 million bopd in 2020 to 14.2 million bopd by 2035
  • U.S. crude oil pr0duction is projected to remain at least 12 million b/d through 2050, as far out as EIA currently models
2020 is next year. I find it amazing that the US will be at 13.1 million bopd production by the end of next year. I assume production in the Bakken and the Eagle Ford is about ready to plateau which means huge growth in the Permian.

The lede at the linked article:
Since 2008, the American shale oil boom has grown domestic crude production some 150% to 12.4 million b/d.
It's been a huge shale party especially led by North Dakota and Texas. The Bakken in North Dakota, and the Permian and Eagle Ford shale plays in Texas account for some 60% of U.S. crude oil production and 85% of U.S. shale oil production.
The Permian is now the largest oil field in the world, surpassing Saudi Arabia's giant Ghawar.
Also in the Permian, I would be remiss not to mention New Mexico, where crude production since 2008 has jumped 5.5-fold to around 0.9 million b/d. Since the beginning of last year, EIA reports that output in the Bakken is up 25%, the Permian up 55%, and the Eagle Ford up 10%.
There are folks who feel that New Mexico will move into second place, ahead of North Dakota in terms of oil production in just a few years. 

US To Be Net Exporter Of Crude Oil And Petroleum Products -- October 12, 2019


Later, 8:29 p.m. CT: this is pretty funny. I had second thoughts about posting the "original post" earlier this evening. I was writing about something I knew very little about and on top of that getting well ahead of my headlights. I was just about to put this post in draft / take it off the blog but I was "saved" by a very nice comment from a reader which I will bring up here for easier access. Once I post something, I do not like to pull it down except under very extenuating circumstances. I've discussed this "policy" before. So, a huge "thank you" for a reasonable response to this post. Here is the first comment, from a reader:
1. Be careful about comparing a weekly data point to monthly data. Weekly data of all kinds tends to have worse quality (i.e. more often wrong) and (even when correct) to be more subject to random variation.

2. Here is the annual refinery utilization, based on monthly data. You can click menu at top and look at monthly also. I prefer the annual view since there is a lot of variation even in the monthly data from seasonality and specific refinery maintenance. And then annual compares well to the time frame of the 2007 to present trend:

I think it mostly looks pretty stable, although maybe higher towards the end of the oil boom (~2014), versus 2008 time frame. And then pretty high in 2018 as well. But again, you just read too much into an isolated weekly or even monthly datum on refinery usage--it just "bounces" a lot.

3. Yes, we are definitely becoming a "merchant refiner" (i.e. importing crude and exporting products, like Singapore). This is mostly to Latin America (LATAM). Still pales in comparison to our internal use. But it's enough to be noticeable in world trade flows. Note: it's not just advantaged crude in the US that has allowed this. A lot of it is because of having advantaged natural gas (a significant operating expense in refinery budget).

4. Definitely we are exporting a fair amount of gasoline (and even more of diesel), from refineries. However, more than 50% of the "products" net exports (of ~3 MM bpd) is from NGLs (i.e. gas plants, not refineries). 
Original Post
Back to this post with these two graphs (same underlying graph, one with with a lot of clutter; one without):

I was surprised that no one spotted something very interesting, but it required connecting dots from two different sources.

The US will be a "net exporter of crude oil and petroleum products" next month.

A reminder about the word "net."

"Net" in this case means subtracting exports from imports or vice versa. In this case:
- imports
more exports than imports.
Net exporter.

A reader reminded me this was not simply crude oil. If it were crude oil only, the US would still be a net importer of crude oil. Apparently it will take another 4 million bopd for the US to be a net exporter of crude oil.

The US will be a net exporter of crude oil and petroleum products. Petroleum products is the stuff that is, for the most part, produced at refineries. Some components qualify as petroleum products but don't require refining. At least that's how I understood it. I could be wrong.

But this is the point.

Petroleum products.

US is to be a net exporter.

One would think the refineries would be operating all-out to hit that record.

In fact, US refiners have been working well below their capacity for the past two to four weeks according to the EIA weekly petroleum report, around 86% when they routinely operate at 96 to 98 percent capacity.

Since I haven't seen anyone else comment on this I assume it doesn't mean anything but it sure seems interesting to me.

Something tells me "Focus On Fracking" will provide an answer this Sunday night.

Natural Gas Injection

By the way, speaking of "Focus on Fracking."  From last week, October 6, 2019:
... the quantity of natural gas held in storage in the US last week increased by 112 billion cubic feet to 3,317 billion cubic feet, which meant our gas supplies were 16.3% more than the 2,852 billion cubic feet that were in storage on September 27th of last year, while still a half percent below the five-year average of 3,335 billion cubic feet of natural gas that have been in storage as of the 27th of September in recent years....
... this week's 112 billion cubic feet injection into US natural gas storage was a bit more than the forecast for an 109 billion cubic feet injection, while it was well above the average 82 billion cubic feet of natural gas that have been added to gas storage during the fourth week of September over the past 5 years, the 27th such average or above average storage build in the last 29 weeks...
... the 2,139 billion cubic feet of natural gas that have been added to storage over the 27 weeks of this year's injection season is the second most for the same period in the modern record, eclipsed only by the record 2204 billion cubic feet of natural gas that were injected into storage over the same 26 weeks of the 2014 natural gas injection season, a coolish summer when there were no injections below 76 billion cubic feet…. 
... as it turns out, that 112 billion cubic feet increase in natural gas storage was the largest on record for the month of September, and the second highest Fall injection in the modern records for this storage report ... 

Story Of The Year? US Crude Oil Imports Set To Plummet Next Month -- Look At The Reason Why --- October 12, 2019

I know. I write that a lot: "Story of the year?"

It's going to be tough to sort out the top energy stories for the year.

But with all the folks over at Twitter heralding this story, one begins to think it's going to be a big, big story. I think this is the third or fourth link regarding this story that I've posted on the blog in the last two days.

Again, from another source, this time from a contributor over at SeekingAlpha:
  • US crude imports are about to set a new monthly low this month. We are seeing October US crude imports coming in at ~6 mb/d
  • next week will show elevated imports of ~7 mb/d followed by sub ~6 mb/d for the following three weeks. 
  • the reasoning behind such low imports is largely thanks to elevated demand pull from Asia and the rest of the world. 
  • now for a reference point, US crude imports were 7.544 mb/d in October last year.
  • so the combination of low crude imports and elevated crude exports this month will see US crude storage counter-seasonally decline.
The historical graph:

Are You Kidding Me? -- October 12, 2019

Quick! What does PHEV stand for?

I know the "H" is hybrid.

And "EV" is well, EV -- electric vehicle.

But I forget, what does the "P" stand for?

Honda, Mitsubishi, Volvo, others have PHEVs.

Oh, there it is -- "plug-in" -- I completely forgot. LOL.

Okay, there you have it.

But are you kidding? In this weekend's "Off Duty" section of The WSJ, the automobile guy has a full page article on the Range Rover's Hybrid SUV.

Price: $69,500 to $114,500.

Range? I quote in full from the article:
The PHEV's problem is the technical overhead relative to its delivered performance. At the absolute best, fully charged, the Sport P400e can squeeze maybe 25 miles of all-electric from its 13.1kW/h battery -- though I never saw close to that in my time in the car. Even in the first few miles of low-to-moderate speed urban driving -- like I'm on my way to a funeral in Eco mode -- the little turbo four (fossil fuel) engine would [take over]. Dang. That was a short virtuous spiral. 
Are you kidding me? $75,000 for a PHEV that has an electric range that barely gets 25 miles?

By the way, to compare, for NASA's Apollo missions to land men on the moon, the lunar excursion module's battery:
  • 65 kW-hr at 4 kW max for a 35-hr lunar stay
This battery brought the Apollo 13 astronauts safely back home over the course of four days and some 500,000 miles.

Shooting Fish In A Barrel -- October 12, 2019

The Bakken is simply staggering. I do this for myself and for newbies. Regular readers know the drill.

In this case, I simply went back to the wells that came off the confidential list in 4Q13 -- six years ago, and simply went through them one-by-one until I got bored. Well after well showed a jump in production, and the jumps were not subtle. In the past fifteen minutes, these wells updated. Again, these are "old" wells by Bakken standards -- completed six years ago, and now show a bigger jump in production than the original completion in most (if not all) cases:
  • 24771, Petro-Hunt, Colgan; from 400 bbls/month to 1,200 bbls/month;
  • 24739, Bruin, Antelope-Sanish, from 1,000 bbls/month to 43,000 bbls/month (no typo);
  • 24738, Bruin, Antelope-Sanish, from 2,000 bbls/month to 21,000 bbls/month;
  • 24737, Bruin, Antelope-Sanish, from 2,000 bbls/month to 20,000 bbls/month; 
  • 24338, Bruin, McGregory Buttes, from 4,000 bbls/month to 13,000 bbls/month;
  • 25191, QEP, Poncho 3-3-10BH, from 3,000 bbls/month to 22,000 bbls/month;
Remember, the costs are minimal compared to a greenfield well. And, the operator knows he/she will strike oil.

Huge Production Jump -- From 3,000 Bbls/Month To 22,000 Bbls/Month -- October 12, 2019

The well:
  • 25191, 1,863, QEP, Poncho 3-3-10BH, Grail, t7/13; cum 517K 8/19;

Small Jump In Production -- From 4,000 Bbls/Month To 13,000 Bbls/Month -- October 12, 2019

As one goes through these wells, one has to remember, there were no costs involved with leasing; roads out to the site; pipelines out to the site; permits; environmental impact statements -- simply go out, re-work, re-frack the identified well, or better yet, frack a new neighboring well. This is why break-even costs in much of the Bakken is less than $15/bbl.

The well:
  • 24338, 2,576, Bruin, Fort Berthold 148-94-33D-28-4H, McGregory Buttes, t8/13; cum 502K 2/19; offline 2/19; remains off line 8/19; 

Jump In Production -- From 2,000 Bbls/Month To 20,000 Bbls/Month -- October 12, 2019

The well:
  • 24737, 2,224, Bruin/HRC, Fort Berthold 152-94-15A-22-7H, Antelope-Sanish, t10/13; cum 94K 6/14; 
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

Jump In Production From 2,000 Bbls/Month To 21,000 Bbls/Month -- October 12, 2019

The well:
  • 24738, 2,171, HRC, Fort Berthold 152-94-15B-22-6H, Antelope-Sanish, t10/13; cum 271K 6/18;
Jump in production:
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

Jump In Production From 1,000 Bbls/Month To 43,000 Bbls/Month -- October 12, 2019


April 11, 2020: update here.

Original Post

The well:
  • 24739, 2,397, Bruin, Fort Berthold 152-94-15B-22-5H, Antelope-Sanish, t10/13; cum 461K 8/19:
Recent production:
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

Zero production between 1/19 and 5/16 -- almost three years of no production; prior to 5/16:

Nice Little Bump In Production -- October 12, 2019

The well:
  • 24471, 608, Petro-Hunt, Rose 16-24HN, Colgan, t7/13; cum 185K 8/19;
Recent production;

PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

Reality Sucks -- October 12, 2019

Quick: China accounts for what percent of global EV sales?

Answer: 60%.

What would happen -- or what would the tea leaves tell you -- if EV sales in China start to fall.

Operative word: "if."

Well, it's no longer "if."

From the instituteforenergyresearch:
Sales of electric vehicles in China are slowing; year-over-year, EV sales dropped 5% in July, 2019, and dropped 11% in August, 2019 -- and this is in a centrally-managed economy wiht goals to cut coal usage.
I was unaware of that. That's huge. It's huge that EV sales in China last year totaled 1.3 million vehicles, or 60% of the global market. But then this: not only did EV sales fall in China, but sales fell for the first time decades last year, declining 3 percent, before falling eleven percent (11%) in the first eight months of 2019. The analysts then blame:
  • China's slowing economy;
  • China's trade war with the US;
  • reduction in government subsidies
  • removal of sales restrictions on traditional cars.
Gee whiz, Sherlock, which of those four ... well, let me re-phrase the question. How would you rank those four factors? Not ass-backwards as the writer of this article. This is likely the real ranking of what is killing EV sales in China:
  • removal of sales restrictions on traditional cars (yeah, the Chinese are like Americans: they like muscle cars; they can't find charging stations)
  • reduction in government subsidies (same  phenomenon we've seen in every country, including Norway)
  • China's trade with with the US
  • China's slowing economy
Wow, the "real" list is exactly reverse order of that presented by experts.

The graphics at the linked article show how bad things really are for EV sales in China.

 I would post those graphics, but I'm not interested. Ready to move on. Maybe I'll post them later.
But I think the real question is this: in a centrally-managed country that could literally tell its people what cars to buy, why did China make this decision to:
  • remove sales restrictions on traditional cars
  • reduce government subsidies for EVs
Two words:
  • coal
  • cash 
Institute for Energy Research? At wiki.

Carbon Carbon; CO2-EOR; And, Re-Fracking -- Clearing Out The In-Box -- October 12, 2019

CO2-EOR, from Geoff Simon's top North Dakota energy stories this week (October 12, 2019):
Denbury Resources has submitted an application to the ND Public Service Commission seeking permission to build a pipeline that will bring carbon dioxide to Bowman County as part of an enhanced oil recover project.

The 12-inch diameter welded steel Denbury Green Pipeline would be just short of 18 miles in length, with about 8.5 miles in Fallon County, Montana, and the remaining 9.2 miles in Slope and Bowman Counties. The pipeline would enter the state nearly due west of Marmarth in southwestern Slope County, and terminate about six miles south of the community in Bowman County.

The CO2 will come from the Exxon Mobil Shute Creek Gas Plant in LaBarge, Wyoming, and the ConocoPhillips Lost Cabin Gas Plant in Lysite, Wyoming, and be transported to Denbury’s Bell Creek EOR Development in Powder River County, Montana.
The new pipeline will connect at a point 6.3 miles southeast of Baker, Montana. Denbury estimates the price tag for the North Dakota portion of the pipeline will be $9.2 million.

The project will provide for tertiary oil recovery from Denbury’s production wells through injection of CO2 into the oil reservoir which will result in increased extraction and utilization of crude oil resources.
Re-Fracking: Next Big Trend In The Bakken?
From The Williston Herald. This should get one's attention: on average, re-fracking should result in 350,000 bbls of additional crude oil from these old wells. The figure was based on an analysis of 100 or so wells in the Killdeer area.

Carbon Capture

Project Tundra, from The Bismarck Tribune, September 17, 2019:
  • carbon capture
  • source of carbon: a coal-fired power plan tin Oliver County
  • project is described as "complex"
  • cost of project if ever approved: $1 billion
  • US DOE: awarded $10 million for a front-end engineering study
  • recipient of the $10 million: Fluor
  • seismic survey has begun near Center, North Dakota