Saturday, November 16, 2019

A CLR Hawkinson Well With A 13-Fold Jump In Production -- November 16, 2019

The CLR Hawkinson wells in Oakdale oil field are featured often on the blog. I don't think I have covered this particular well in a stand-alone post recently.

The well:
  • 24224, 681, CLR, Hawkinson 5-22H, 33-025-01954; Oakdale, middle Bakken, 30 stages, 2.8 million lbs, t9/13; cum 411K 41/9; went offline 3/19; not recently fracked;
Recent production:
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

So, what's the deal. It took a bit of sleuthing, but here's the answer. The sister wells on this pad, #24223 and #24225 also showed a significant jump in production.

It was obvious a neighboring well (or wells) had been recently fracked. None of the other Hawkinson wells had been recently fracked, and none of the others to the east showed a jump in production.

However, there it was, right on cue, a CLR Carus well in the neighboring drilling unit to the west had been fracked in 4/19. So, halo phenomenon. Clear as drilling mud.

The Saudis have not commented on this phenomenon but it is real and does effect the EUR.

The Bird Bear Wells Have Been Completed; A Neighboring Well Goes Over 500K Total Bbls -- November 16, 2019

The Bird Bear wells:
  • 35652, 3,243, WPX, Bird Bear ...HA, Spotted Horn, t9/19; cum 46K over 24 days; cum219K 2/20; a 62K month;
  • 35650, 3,901, WPX, Bird Bear ...HB, Spotted Horn, t9/19; cum 48K over 23 days; cum 238K 2/20; a 59K month;
  • 35651, 3,150, WPX, Bird Bear ...HS, Spotted Horn, t9/19; cum 41K over 22 days; cum 251K 2/20; a 55K month;
  • 35649, 3,090, WPX, Bird Bear ...HU, Spotted Horn, t9/19; cum 35K over 20 days; cum 202K 2/20; a 42K month;
  • 35653, 3,412, WPX, Bird Bear ...HW, Spotted Horn, t9/19; cum 37K over 24 days; cum 227K 2/20; a 57K month;
  • 35648, 3,261, WPX, Hackberry 34-27HG, Spotted Horn, t9/19; cum 48K over 19 days, extrapolates to 75,693 bbls/30-day month; cum 226K 2/20;
Neighboring wells:
  • 18803, 1,066, WPX, Morsette 35-26H, Spotted Horn, t10/10; cum 502K 2/20; off line as of 7/19; remains off line 9/19; coming back on line 2/20;
  • 25175, 1,199, WPX, Morsette 35-26HX, Spotted Horn, t9/14; cum 301K 2/20; off line as of 7/19; remains off line 9/19;
The graphic:

DAPL Operator's Activity In Texas Will Positively Affect The Bakken -- November 16, 2019

Link here to The Williston Herald. Paywall, unfortunately. Archived.

Data points:
  • the DAPL operator has extended the open season on Dakota Access just to accommodate the option to offer HFOTCO and the Houston Shipping Channel market to Energy Transfer's customers
  • background:
    • in September, 2019, Energy Transfer acquired SEMGROUP in a $5 billion deal (see this post)
    • that acquisition included the completion of the Ted Collins pipeline in 2021
    • the Ted Collins will  connect the dots between two of the nation’s largest oil terminals, one at the Houston Shipping Terminal, or HFOTCO, and the other in Nederland, Texas
    • already there is more than one million barrels per day of existing crude oil capacity at the terminals
    • the company plans to expand that to over two million barrels per day going forward
    • the Ted Collins pipeline would start with an initial capacity of more than 500,000 barrels per day capacity, beginning in 2021
  • the extended supplementary season for the Dakota Access pipeline won’t delay the planned expansion of the line
  • the demand for shipping volumes on the line is very high. So high, that if the company could “snap its fingers” and have an additional 400,000 to 500,000 barrels per day in capacity, the company thinks it would likely be immediately filled
  • then this, from the CEO:
    • “Nothing really competes with Dakota Access,” Mackey said. “All of these (other) projects, when you look at the stacking of fees and where those markets are and the timing to get there, nothing really compares to a project that can deliver to the vast majority of the mid-continent refineries and then bring it down to the Gulf Coast to all the refineries in Texas and then through the Bayou Bridge get it to the St. James Markets.”
  • company officials expect to ultimately expand the capacity of Dakota Access to 1.1 million barrels of Bakken crude oil per day
  • background:
    • this will be done in phases, with the first expansion beginning in mid-2020 with 30,000 barrels per day, pending successful completion of permitting for new compressor stations
    • additional capacity, based on commitments in the supplementary binding season, will be brought into service by early 2021
    • to accomplish this, Energy Transfer plans to build three compressor stations, one in North Dakota, one in South Dakota, and one in Illinois

From The Saudis: A Technical Analysis Of The Bakken -- November 16, 2019


November 17, 2019: note comments below. From a reader:
a. I think you are being too hard on them, to dismiss all the work based on one thing.

b. I don't think you really understand what they are doing. They are probably trying to do some math on total average infill density, without manually mapping each lateral. If you follow the directions in the paper and go to Figure 8, like they tell you to, this is explained in a very upfront manner:

"(c) Calculate wellhead density by counting the number of wells on each of the one-square-mile squares. This map is not the real well density map, because it only shows
the wellhead density.
(d) Calculate an approximate well density map from wellhead density map. The algorithm is as follows: (1) For each well, record its lateral length and calculate the number of squares, n, intercepted by the lateral. For example, a 5000 ft lateral will occupy one square and a 10,000 ft lateral will occupy two squares because one mile is 5280 ft. (2) Search for the least occupied n squares in all possible directions (i.e., north, northeast, east, southeast, south, southwest, west and northwest).
(3) Increase the value of well density by 1 well/mi2 for every least dense square found. (4) Repeat the process until all wells in the area of interest are exhausted.
(e) Calculate an infill potential map by subtracting the calculated well density from the maximum number of wells, Nmax (e.g., Nmax = 4 wells/mi2 to avoid frac hits). The summation of all values in the map is the infill potential for the one-square-mile grid.

What they are doing is perfectly adequate. (It's actually similar to a point that I made to you a while ago, when you were confusing wells per unit (for larger than normal units or longer than normal well lengths, with what matters, horizontal lateral spacing.)

November 17, 2019: from a different, a graphic that the Saudis missed:

November 17, 2019: after seeing the paper at the original post, a writer suggested a paper delivered at an oil conference in Houston, TX, July, 2018, "Production Optimization Using Machine Learning In Bakken Shale." The abstract is available but there is a fee for the entire paper. The abstract, but no conclusion:

Researchers from both industry and academia have studied the tight oil resources intensively in the past decade since the successfully development of Bakken Shale and Eagle Ford Shale and made tremendous progress.
It has been recognized that locating the sweet spots in the regionally pervasive plays is of utter significance.
However, we are still struggling to determine whether the dominant control on shale well productivity is geologic or technical.
Given certain geological properties, what is the best completion strategy?
Most of the previous studies either analyze the completion data alone or divide the entire play into different data clusters by map coordinates and depth, which may neglect the heterogeneity in thickness and reservoir quality parameters.
In our study, we first conducted stratigraphic and petrophysical analyses, using the regional variation in depth, thickness, porosity, and water saturation to capture the regional heterogeneity in the Bakken Shale Petroleum System.
We selected approximately 2,000 horizontal wells targeting Mid Bakken Formation with detailed completion records and initial production dates during 2013 and 2014. Completion data inputs include normalized stage length, stage counts, normalized volume of fluid, and normalized volume of proppant.
November 17, 2019: a reader with experience in the oil fields in Saudi Arabia as well as experience in Saudi academe of Saudi Arabia did not mince words when he saw this article. He wrote:
Like you say, bottom hole locations are always reported. They say not. This proves they are either hopelessly careless,simply too lazy to really do the hard research or intentionally vague. Does it matter which one it is? No. 
He wrote more but not sure if anonymity might be an issue, so I will leave it there.

Original Post
A reader sent this comment and the link to this peer-reviewed technical article:
This link says a lot what they are thinking in the Kingdom: 
In a way some of the most interesting [data/conclusions] I ever have read about the Bakken system. 
And this is great to see that that they have a [well-argued] forecast, but [likely quite short].
And you have a map of the core area in the middle Bakken and Three Forks. I nearly agree about that part. 
But my initial thoughts are that they think there will only be 8 wells in a spacing unit and no mention of the famous halo effect. 
But anyway it's so great to see what the Kingdom thinks. And they will be surprised.
I agree with the reader. I was going to go through the article and make comments as I went along, but a) the paper in many respects is too technical for me; 2) the authors are experts (and I'm not); 3) the authors have access to databases, computer programs, and statistical analysis I cannot possibly replicate.

The reader is correct: the authors assume a maximum of eight wells in each 1280-acre drilling unit. Perhaps that is accurate as an average across the entire Bakken but my hunch is that there will be a minimum of four wells in each 1280-acre unit in non-core North Dakota Bakken, but upwards of 12 to 24 wells in the core Bakken.

Their conclusions in bold that jumped out at me, my comments in red:
  • author's conclude that newly completed wells have almost the same ultimate recovery as the older ones, despite their much higher initial oil rates
    • they have the databases and the stastical data, but anecdotally, I'm certainly not seeing that
  • ultimately, we predict that the 14,678 existing wells in the Bakken will produce 5 billion bbls of crude oil by 2050 (~ 340,000 bbls/well)
    • currently, the Bakken is producing about 1.4 million bopd or "365 x 1.4 million bopd" = 511 million bbls per year 
  • after drilling an additional 4,400 new wells at the rate of 120 wells/month, the core are of the Bakken will be drilled out by 2021, and ultimate recovery will be 7 billion bbls of oil
  • with 26,500 more wells drilled in the noncore area until 2041, ultimate recovery in the Bakken might be 13 billion bbls of oil, but drilling of such scale is unlikely to happen 
Compare their conclusions with the conclusions of the USGS, the 2013 assessment. Their conclusions, some of them almost laughable:

• We have provided a transparent hybrid method of forecasting oil production at shale basin scale.

• Our statistical approach generates the non-parametric well prototype templates that are used to calibrate our physics-based flow scaling with late-time radial inflow.

• In particular, our average P50 well prototypes follow the physics of linear transient flow and are used to calibrate the physics-based scaling extensions to 30 years on production.

• A combination of GEV statistics with physical scaling matches historical production data almost perfectly and gives a smooth, physics-based estimate of future production.

• Our prediction of the Bakken future is optimal in the least square sense; in other words, our prediction is as good as it gets given all data at hand.

• Regulators may want to consider our approach as a prerequisite to booking reserves in oil shales (my favorite).

• Newly completed wells have almost the same ultimate recovery as the older ones, despite their much higher initial oil rates.

• Ultimately, we predict that the 14,678 existing wells in the Bakken will produce 5 billion bbl of oil by 2050 (∼340 kbbl/well).

• After drilling additional 4,400 new wells at the rate of 120 wells/month, the core area of the Bakken will be drilled out by 2021, and ultimate recovery will be 7 billion barrels of oil.

• With 26,500 more wells drilled in the noncore area until 2041, ultimate recovery in the Bakken might be 13 billion barrels of oil, but drilling of such scale is unlikely to happen.

• Policy-makers should beware of assuming that oil boom in the Bakken shale will last decades longer.


I think the biggest problem I have with this paper is the fact that "all" locations drilled prior to 2014 will eventually be re-fracked using up-to-date completion strategies . In addition, "all" Bakken wells will go through a series of small and large re-fracks over the course of their lifetimes, something not addressed in the paper. The analysis seems to be done using "conventional" methods.
Will we ever see a new USGS assessment of the Bakken?

Miscellaneous Comments
In Progress

Page 9, line 163:
We have calculated the number of wells that can be drilled in the future in every one-square-mile pixel of the grid that covers the entire Bakken play. In order to calculate infill potentials, one should first determine well density. However, the publicly available data rarely provide information about the bottomhole locations of the wells. Instead, only surface locations are reported as latitude-longitude coordinates. Therefore, we have developed an algorithm that allows us to predict the bottomhole well density from surface well locations.
Comment: in the big scheme of things, this does not matter, but every permit specifies the exact location of the bottomhole, so I'm not quite sure what the authors mean when they say "the publicly available data rarely provide information about the bottomhole locations of the wells." 

Watford City Airport Update -- November 16, 2019

From Geoff Simon on Friday, November 15, 2019:
Plans were approved this week to begin construction work next spring on a longer, re-aligned runway at the Watford City Airport. But instead of attempting to finish the work in a single construction season, the work will be spread over two years to minimize downtime at the airport.

The Watford City Airport Authority approved design work for a 5,800 foot concrete runway, which carries an estimated price tag of $26.4 million. The city expects to bid the first phase of the project in February.

Construction of the new runway will eventually require the current 4,400 foot runway to be shut down, but airport officials decided to spread the work over two years to shorten the time the airport will be out of service. Next summer the city will complete grading and other dirt work that won't affect existing airport operations, and complete work on the concrete runway in 2021. The second phase of the project which will require shutting down all air traffic is expected to require about six months to complete.

ONEOK Bringing Additional Natural Gas Processing Capacity On Line For North Dakota -- November 16, 2019

From Geoff Simon on Friday, November 15, 2019:
By January 2020, ONEOK Corporation will have constructed enough natural gas processing capacity that it will be able to handle nearly half of North Dakota's total production. January 2020? That's two months from now.
Natural gas processing plants in North Dakota are tracked here.

The state topped 3 billion cubic of natural gas production per day in August, but ONEOK will soon have the capacity to process 1.4 BCF per day.

Dick Vande Bossche, VP for Commercial Gas Supply with ONEOK Rockies Midstream, told members of the legislature's interim Energy Development and Transmission Committee this week that the company brought in service in October its Demicks Lake I plant in McKenzie County. The plant has the capacity to process 200 million cubic feet of gas per day.

Vande Bossche said ONEOK is also on schedule to bring Demicks Lake II, a second plant capable of processing 200 MMcf/d, in service sometime in January 2020.
A third plant - Bear Creek II with 200 MMcf/d capacity - is under construction in Dunn County and will be in service the first quarter of 2021.
And Vande Bossche also told legislators that ONEOK has plans for yet another 200 MMcf/d capacity on the drawing board.

"We filed certification with the PSC for another 200 million per day processing plant in McKenzie County, so that's working its way through the approval processes," Vande Bossche said. "We have interim funding to do some long lead item purchases as it relates to that 200 million a day processing facility."

He said final execution of plans for the additional gas processing plant are contingent on board approval of the project. ONEOK is also nearing completion of its Elk Creek Pipeline that will move up to 240,000 barrels per day of natural gas liquids to processing facilities in Kansas and points south. It's expected to be fully operational by the end of 2019.

Not A Bit Surprised -- November 16, 2019

From Geoff Simon on Friday, November 15, 2019:
The preliminary oil production numbers for the month of September will not be down as much as earlier predictions. The Director's Cut is scheduled to be released November 19, 2019.
Lynn Helms, director of the Department of Mineral Resources, told a legislative committee this week that the wet weather in September did cause a drop in production, but it will only be about two percent lower than the August numbers.

Helms said production technology continues to improve, especially in the Bakken which he said is the "absolute best place in the country to put a drilling rig."
He said the Bakken continues to out-perform the Permian, the Eagle Ford, the Niobrara and other shale plays around the United States. And he said the improvements are happening quickly.

"A new well coming on in 2019 will produce 50-to-70 percent more in the first 18 months than a well that was completed just a year ago using the new technologies," Helms said.

The downside to the story is that associated natural gas production continues to outpace oil production, and the absence of adequate infrastructure to handle it has constrained industry growth.

"You can see the gas curve is much steeper than the oil curve and that's what really is our struggle as we go forward over the next five to 10 years is, the oil curve is where the money's at, the gas curve has got to be managed."

North Dakota Story -- November 16, 2019

What a treat! What a great story. Sent to me by a reader. The gentleman was born one year earlier than my dad and lived grew up in the same area, mentioning Newell, SD, in the story.

What a treat. One may want to archive it. Archived.

Link here.

By the way, "Krebsbach" is a familiar name in North Dakota, not just the Bowman area but also in Williston.

See first comment, and this link.


I don't know how the pricing works, but our older daughter and our granddaughter Sophia are really, really excited. Their household has signed up for Disney+. My daughter says that because they already had Hulu, the monthly subscription for Hulu plus Disney+ remains (about) the same. She said the monthly subscription prices has remained the same. I added the "(about)" because something tells me there must have been some additional cost, although perhaps the introductory period is such that the price increase, if any, is not seen for the first year or so.

Sophia doesn't mind the monthly price. LOL.

Apparently it's a lot more than just Disney "stuff." It includes National Geographic, other "libraries."

I wonder when TCM will go the subscription route.

I'm more than satisfied with Amazon Prime, Perry Mason, and my library of DVDs and Blu-Ray.

Week 46: November 10, 2019 -- November 16, 2019

Top international non-energy story:
Top international energy story:
Top national non-energy story:
Top national energy story:
Top North Dakota non-energy story:
Top North Dakota energy story:
Geoff Simon's top North Dakota energy stories:
Bakken 101:
Horse racing:

The Whining Gets Tedious -- November 16, 2019

I normally would not have posted this but there was so much whining, this needed to be posted. For the record: I do not care for Garth Brooks all that much. I did not watch the awards ceremony but social media told me all I needed to know.

From The Washington Post: Garth Brooks won CMA Awards entertainer of the year. Here's why many country fans are furious. The lede:
On Wednesday night at the Country Music Association Awards, the legendary Garth Brooks won entertainer of the year — the final and most prestigious prize — for the record-setting seventh time in the show’s history. He has received the award three out of the past four years. He’s about to wrap up a massive, sold-out stadium tour. He has a Top 20 single on country radio. He’s part of a beloved celebrity couple with Trisha Yearwood. He’s known as one of the nicest people in Nashville.

Yet, the reaction from many country music fans at Brooks being named the winner? Absolute fury.

The vitriol was pouring out on Twitter after the show; the awards show’s Facebook and Instagram accounts were inundated with enraged comments. In many instances, however, the backlash wasn’t even necessarily about Brooks. His legacy is undeniable. The anger was about who didn’t get the prize. Brooks won out over Carrie Underwood, Eric Church, Chris Stapleton and Keith Urban, who was last year’s winner.

The first enraged fandom? Underwood’s. The “American Idol” winner turned country music superstar has steadily built a phenomenal career over the past 15 years, with tons of smash songs and millions of albums sold. Not only has she co-hosted the CMAs every year since 2007 (formerly with Brad Paisley, this time with Dolly Parton and Reba McEntire), but she has also been nominated for entertainer of the year a mere two times despite her wildly successful résumé. This year, during the awards’ eligibility period of July 2018 through June 2019, she released her sixth album, “Cry Pretty,” which had three hit singles. (She also co-produced it.) The entertainer prize is often informally considered an award that favors touring, and for the past year, Underwood headlined a giant arena tour to support the record.
If I had all the money and the interest in going, but could go to only once concert, whose would i attend? Carrie Underwood or Garth Brooks?

One has to ask: if she has co-hosted the CMAs every year since 2007 and has been nominated only twice for entertainer of the year, one needs to ask.... why?

By the way, who votes: 7,000 members of the CMA trade group.

I guess we need to impeach/convict Garth Brooks and/or ask for a re-vote.

I honestly don't know if I've ever heard a Carrie Underwood song. And I don't know if I've ever heard a Garth Brooks song other than his first dozen big hits. I bet I'm not alone.  Even now, while writing this, I'm listening to Garth Brooks; I have no interest in Carrie Underwood. I have never cared for karaoke singers and that's what she was back in 2004 when she hit the big stage. Back in 2004, I was going through my own mid- to late-life crisis and country music was the last thing on my mind, except for Nora Jones. And, yes, at heart, Nora Jones is a country singer:
At the 45th Grammy Awards in 2003, Jones was nominated for eight Grammy Awards and won five: Best New Artist, Album of the Year, Best Pop Vocal Album, Record of the Year, and Best Female Pop Vocal Performance for "Don't Know Why".
This tied Lauryn Hill and Alicia Keys for most Grammy Awards received by a female artist in one night.
Jesse Harris won Song of the Year for "Don't Know Why" while Arif Mardin won Producer of the Year. The album won Best Engineered Album, Non-Classical. Come Away with Me was certified platinum by the Recording Industry Association of America (RIAA) for having sold one million copies. In February 2005, it was certified diamond for selling ten million copies.
The End of the Line, Supergroup: The Travelin' Wilburys

By the way, did the best supergroup ever win a music award?

By the way, the best concert I've attended? Liberace in Las Vegas. I saw two of his shows about four years apart.

The second best big-name concert: Bob Dylan in San Antonio. But no comparison. The former, Liberace, was a showman; the latter definitely not. I don't think poets are show people. Also, from what I've seen, Garth Brooks is a real, real showman. It would be hard to compete with him. He did not win "best song of the year"; he won "entertainer of the year." There's a huge difference.

Free At Last, Free At Last -- Babylon Bee -- November 16, 2019

From the Babylon Bee via Powerline, free at last, free at last ....

Natural Gas, Chesapeake, Jerry Jones, Comstock, And All That Jazz -- November 16, 2019

The other day it was reported that Comstock is in talks with Chesapeake to buy the latter's Haynesville's assets. This is going to be quite a story if it plays out the way Jerry Jones wants it to play out. Story at Reuters.

Jerry Jones is only 77 years old. He seems more mellow. He seems like he's not done yet. 

I'll come back to this one later.

The article has eight comments, so far.
He will join Kinder Morgan...KMI in a make use of not in service, idle HUGE Pascaguola deep port owned by KMI...with all permits; a 2 year's gain at least just on pérmits....for a MONSTER new LNG export plant own by Jerry Jones, Comstock ... a win-win for both!!!
Not so fast. Do not be surprised if this deal is not scuttled by CVX (Chevron), XOM (Exxon Mobil) or an activist investor that has accumulated 2%+ over the past week. Too many good assets held by CHK and there are many deep pockets that won't sit idly by and watch CHK be cut up like a T-bone steak by some Texas tycoon licking his chops, while CHK is primed to be taken out now. Something is going to happen here soon and it's going to be big. Just wait for the next PR to drop any day. Too many eyes on CHK right now and with over $1 billion in stock changing hands in 7 days, CHK is far from done and there is more news to come with 999.999% certainty. Go USA!!! Go CHK!!! Go Dow 30,000!!!

Google -- WSJ -- November 16, 2019

Excellent example why the print edition is so much more useful than the electronic edition, but there's nothing we can do about it. It's water under the bridge. It is what it is. I'll come back to this article also.

From The WSJ, November 15, 2019. Unfortunately it's behind a paywall, but it's one of the few subscriptions I have. In addition, it's "free" at Starbucks.

I'll come back to this one later.


Regardless of one's feelings about Ken Fisher, he's opened the eyes of a lot of investors -- those who are paying attention -- about annuities.

Now this, in this week's Barron's: companies have done well getting workers into 401(k). Now they're trying to help people spend them.

A typical-length article for Barron's. But about a third of the way through, the phrase, "additional fee," and then, it started to sound like the writer was taking about converting 401(k)s to annuities.

Wow, wow, wow -- about two-thirds into the article that's exactly what it turned into: a spiel to cnvert one's 401(k) into an annuity if the laws were changed. The writer "complains" that there are only two ways to withdraw money from a 401(k): a lump sump or RMDs.

Disingenuous. There is no maximum on RMDs. One can take distributions (after 70 1/2 years old) of any amount and whenever one wants -- as long as the RMD is met. And, of course, taxes would be forthcoming.

But that would be true of an annuity also (trust me on this one) and, of course, for "an additional fee" to the manager of the annuity.

It looks like this story was a press release from an insurance company disguised as a news story.