Monday, August 5, 2019

Whiting With Three New Permits; Twenty-Eight Permits Renewed -- Crescent Point Very Active -- August 5, 2019

Active rigs:

Active Rigs5964583474

Three new permits:
  • Operator: Whiting
  • Field: Rawson (McKenzie)
    Comments: Whiting has permits for a 3-well Dwyer pad in section 27-150-101, Rawson oil field
Twenty-eight (28) permits renewed:
  • Crescent Point (17): four CPEUSC Jean permits in Williams County;  five CPEUSC Tami permits in Williams County; four CPEUSC Sylven permits in Williams County; four Burgess permits in Williams County;
  • XTO (6): six Cindy Blikre permits i Williams County 
  • EOG (3): three Hawkeye permits in McKenzie County
  • Equinor: one Martin permit in Williams County
  • Resource Energy: a Marshall permit in Divide County
One producing well (DUC) reported as completed:
  • 35378, 1,160, Newfield, Skipjack 149-98-11-2-4H, Pembroke, t6/19; cum --;

Australia Negotiating WIth US On Emergnecy Oil Supplies; A Note From A Reader On Australia - US LNG Exports -- August 2019


Later, 5:11 p.m. Central Time: wow, wow, wow, and wow. How interesting. The rest of the story.

Later, 1:05 p.m. Central Time: the tweet below simply says that Australia is negotiating with the US on emergency oil supplies. No timeline is provided. Is Australia looking out twenty years from now, or a year from now? Here's my take on the likelihood that Australia is negotiating with the US on emergency oil supplies based on data looking:
  • 50 years out: 0% chance or 0% likely that the negotiations are based on data projected for 2075
  • 25 years out: 5% chance or 5% likely that the negotiations are based on data projected for 2050
  • 20 years out: 10% .... projected for 2040
  • 10 years out: 15% ... projected for 2030
  • 5 years out: 20% ... projected for 2025
  • 1 year out: 50% chance
Yeah, the next video on this page might be appropriate. If nothing else, it's fun to listen to.

Original Post 

Memo to "First Squawk": enough with the caps.

Life During Wartime, Talking Heads

With regard to the twitter screen shot above. I happened upon that tweet about 9:00 a.m. this morning. It would have caught my attention regardless but a note from a reader last night "primed" me to see that tweet.

It should be noted this particular reader is particularly knowledgeable about this particular subject.

Here's the reader's note from last night.
That LNG daily export chart will show another 50% to 75% bump by year's end.

Six years out, it will easily double again ... gar own teed.

Current world's leading LNG exporter, Australia, will IMPORT LNG from USA (via Port Kembla's FSRU) in 16 months' time.

Contract with Cheniere has already been signed.
I find that absolutely incredible.

"Americans" have no idea how big this story -- the shale revolution story -- is and will be.

By the way, know what I found most rewarding about that short note? This one word: "Cheniere."

I noted the Cheniere / Chile connecting dot in the linked post above.

MRO Wells In Section 12-150-93 Appear To All Be Back On Line -- Some Huge Wells; Many Reporting Nice Jumps In Production -- August 5, 2019

Newbies: as you look scroll through this post, recall the hand wringing about parent-daughter interference in the Permian. The data below is not atypical for the Bakken, but some fields are much better than others with regard to this phenomenon. Hard to sort out how much has to do with location / oil field, and how much has to do with the operator / completion strategies. Everything I've seen suggests the Bakken operators have a good handle on this issue. Could be wrong.

The well:
  • April 2, 2019: see this post. #33668; #18514; #33431; #23176; and, #21458; and, this post. As of 4/19, older wells still off line; as of 6/19, it appears all wells back on line.
One typical example:
  • 21458, 1,597, MRO, Tara Jo USA 34-12H, Reunion Bay, t1/13; cum 474K 6/19; six years old with jump in production, cum 532K 7/21;
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

Another example, this well over nine years old, drilled in the early days of the boom, huge jump in production, over 9,000 bbls in 14 days when it came back on line:
  • 18514, 672, MRO, Howard USA 11-1H, Reunion Bay, t6/10; cum 541K 6/19; cum 596K 7/21;
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

One of the two daughter wells:
  • 33668, 3,278, MRO, Fannie USA 21-1H, Reunion Bay, t2/19; cum 164K 6/19; cum 365K 7/21;
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

Huge MRO Wells In Reunion Bay, Sited In 8-151-93

Record IPs: when looking at the IPs of the wells on this pad, be sure to compare with "record IPs" at this post.

The well:
  • 20529, 1,523, MRO, Randi USA 41-17H, API: 33-061-01697, Reunion Bay, t9/11; cum 299K 11/20; cum 309K 7/21;
    • November 27, 2018: #20529, neighboring MRO wells in Reunion Bay fracked; remains inactive 5/19; nice jump in production when it came back on line, 6/19; was off line for about a year; back online 11/20;
The jump in production may not last long but for mineral owners receiving no "mailbox money" from this well for ten months or so, this is nice to see.

Recent production:
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

Wells on neighboring pad:
  • 32024, 7,956, MRO, Ness USA 31-17H, Reunion Bay, t10/18; cum 352K 10/19; 54K in 14 days; cum 439K 11/20; cum 463K 7/21;
  • 32025, 6,140, MRO, Becky USA 21-17-TFH, Reunion Bay, t10/18; cum 331K 11/20; cum 350K 7/21;
  • 32026, 4,646, MRO, Hans USA 31-17TFH, Reunion Bay, t11/18; cum 375K 11/20; 49K in first 28 days; cum 420K 7/21;
  • 32027, closest to the Randi USA well, PNC, Post USA 41-17TFH-2B,
  • 32028, looks like it replaced #32027, 5,390, MRO, Ballmeyer USA 41-17TFH, Reunion Bay, t11/18; cum 401K 11/20; 60K in first full 30-day month; cum 430K 7/21;
Example (won't be updated below):
  • 32028, looks like it replaced #32027, 5,390, MRO, Ballmeyer USA 41-17TFH, Reunion Bay, t11/18; cum 355K 10/19; 60K in first full 30-day month;
  • note: produced water significantly less than oil production
  • note: huge flaring; and this is in a "developed" area where gas capture infrastructure should be in place 
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

The graphic: for newbies, the importance of this graphic: parent wells sited in drilling unit to the east; daughter wells -- huge wells -- sited in drilling unit to the west:

Zavanna Well In Stockyard Creek With Nice Jump In Production -- August 5, 2019

The jump in production may not last long but for mineral owners receiving no "mailbox money" from this well for ten months or so, this is nice to see. This well is seven years old; was drilled relatively early in the boom.

The well:
  • 22044, 700, Zavanna, George 19-30 1H, Stockyard Creek, t10/12; cum 380K 6/19;
  • November 6, 2018: #22044, Zavanna, George, API: 33-105-02473; off line; neighboring wells being drilled; will be six months or so before we see anything; still off line as of 12/18; on IA status; back on line as of 4/19 for 8 days; off line 5/19 but still A; wow, huge jump, 6/19;
Recent production:
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

Other wells on the pad:
  • 35170, conf,  
  • 29800, producing,
  • 29799, producing,
  • 35171, drl,
  • 35172, conf,
  • 22044, producing, see above;
  • 35173, conf
The graphics:

Active Rigs -- Energent -- August 5, 2019

Summary of Plays:
  • Permian Basin: -0.2% to 442 rigs compared to last week's 443 rigs 
  • Eagle Ford: stayed flat at 66 rigs 
  • Marcellus: stayed flat at 56 rigs 
  • Haynesville: +2.0% to 52 rigs compared to last week's 51 rigs 
  •  Cana Woodford: -2.0% to 48 rigs compared to last week's 49 rigs 
  • Williston: stayed flat at 47 rigs 
  • DJ-Niobrara: stayed flat at 29 rigs 
  • Powder River: stayed flat at 22 rigs 
  • Utica: stayed stayed flat at 15 rigs

Answer To Pop Quiz -- August 5, 2019

Question: conventional wells or unconventional wells -- which have a higher ratio of produced water, conventional wells or unconventional wells? What is the ratio of produced water-to-oil in conventional wells compared to that of unconventional wells? [PWOR = produced water-to-oil water.]

The answer will be posted Monday, August 4, 2019, sometime during the day after I get caught up with the news that came out over the weekend.

Originally posted here, so some answers/replies will be at that post. 

On another note, 99.9999999%+ Americans can be thankful they had an uneventful weekend. Huge condolences to the families in Dayton, OH, and El Paso, TX.

Answer: conventional wells. And it's not even a close call. [Later, see this post also.]

Best Answer From A Reader

Your question regarding produced water is significant for several reasons. Conventional, vertical production may have 90 to 99 barrels of water for every single barrel of oil produced as a routine matter for older wells.

This is the single biggest expense in low producers and is the main determinant of when to permanently plug a well.

Unconventional in the Bakken is frequently in the 1 bbl water /1 bbl oil range which is pretty remarkable and a huge influence on the long term positive economic potential.

Water handling (for frac'ing in LTO, disposal in conventional and unconventional) is a big component in oil development operations.

Source From The Literature

This is what caught my attention and why I asked the question.

This is a screenshot of the abstract from an article published in 2017 with regard to the Permian.

The third sentence in that abstract: our results show that although conventional wells produce about 13 times more water than oil ... [a]lthough unconventional wells have a much lower PWOR of 3 versus 13 from conventional wells ...

This is the link to that article: At the link you can download the pdf.

Produced Water Vs Flowback

A reader asked the question: what is the difference, if there is a difference, between produced water and flowback. The reader who best answered the original question, also provided this answer regarding produced water and flowback:
On whether flowback is same as produced water?
It is not, but I can not offer any legally/technically precise definition with which to precisely distinguish one from the other.
In the early Bakken years (probably Eagle Ford and Niobrara also), huge amounts of the frac fluid would be somewhat rapidly - within a few days' time - removed from the newly frac'd well. This was partially motivated in not wanting the formation to absorb the water, swell and inhibit production.
In the last 2 to 3 years, it is obvious that operators are maintaining VERY high quantities of frac water underground for SEVERAL months and the now-surfacing water is labelled as flowback. (The earlier years' rapid flowback was - to my knowledge - never officially recorded). This is why when the recent wells' production profiles show 200,000/250,000 barrels produced water first 5 months, purposeful underground retention is indicated.

For me, I apologize to readers. To some extent this was a "trick question." Everyone writing about fracking, including me, writes about the huge amount of water being used to frack the wells. So I was quite surprised to see how much water is actually used in conventional wells.

For me this was incredibly important: with the recent discussion of porosity and permeability, there were sidebar issues regarding water. If oil producers seem hassled by natural gas / flaring, I would imagine that issue pales in comparison to the problem they have with water.

Along with everything else about water in that linked PWOR study, there was a footnote in one of the replies to the porosity / permeability issue with regard to how Saudi Arabia almost "lost"one of their best fields due to water channeling.

So, I apologize for the trick question, but, wow, I sure learned a lot.