Monday, August 5, 2019

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
BAKKEN6-2019267278714664111141814089460
BAKKEN5-20190000000
BAKKEN4-20190000000
BAKKEN3-20190000000
BAKKEN2-20190000000
BAKKEN1-20190000000
BAKKEN12-20180000000
BAKKEN11-20180000000
BAKKEN10-20180000000
BAKKEN9-20180000000
BAKKEN8-201814444030280
BAKKEN7-2018311779174432130192406324
BAKKEN6-20183017391859311296726860
BAKKEN5-20183120542037338290413081292
BAKKEN4-2018301787172032224813961709
BAKKEN3-2018311735169943330597601922

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
BAKKEN6-2019301767017815108821698874717864
BAKKEN5-20193126426263941814638523966226523
BAKKEN4-20193028129284311837541476517233939
BAKKEN3-20193137665374323002256854772346222
BAKKEN2-20192842406422832156059687564451217
BAKKEN1-20193052319532143203280293664070158
BAKKEN12-2018305907458538437038424092879398
BAKKEN11-20181934215335832815537266034998

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:

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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
BAKKEN6-20193068846371341811451263187747
BAKKEN5-20190000477450
BAKKEN4-201981638744411421736
BAKKEN3-20190000000
BAKKEN2-20190000000
BAKKEN1-20190000000
BAKKEN12-20180000000
BAKKEN11-20180000000
BAKKEN10-20180000000
BAKKEN9-20180000000
BAKKEN8-20180000000
BAKKEN7-20180000391239120
BAKKEN6-20182518922107158020411481187
BAKKEN5-2018313352320822834409391235

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



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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
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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: https://pubs.acs.org/doi/10.1021/acs.est.7b02185. 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.
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Sunday, August 4, 2019

Six Wells Coming Off Confidential List This Weekend, Today -- 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.

*****************************************
Back to the Bakken

Wells coming off the confidential list over the weekend, today -- 

Monday, August 5, 2019: 8 for the month; 57 for the quarter;
  • 35982, SI/NC, Sinclair, Uran 7-15H, Sanish, no production data,
  • 34939, SI/NC, Hess, EN-Kulczyk-154-94-2029H-12, Alkali Creek, no production data,
  • 34895, 887, Kraken, Pocasset LE 29-32 1H, Oliver, t2/19; cum 103K 6/19; a nice well;
Sunday, August 4, 2019: 5 for the month; 54 for the quarter;
  • None.
Saturday, August 3, 2019: 5 for the month; 54 for the quarter;
  • 34940, SI/NC, Hess, EN-Kulczyk-154-94-2029H-2, Alkali Creek, no production data;
  • 34155, 537, Oasis, Aagvik 5298 14-26 13BX, Banks, t2/19; cum 156K 6/19; huge well;
  • 34035, 138, Petro Harvester Operating Company, LLC, FLX3 28-33 163-91 D, Portal, a Madison well; t5/19; cum 7K 6/19; a nice well for a Madison well; I might come back to this one; it's a horizontal Madison well;  huge amount of water in first two months; flowback/produced/
Active rigs:

$54.978/5/201908/05/201808/05/201708/05/201608/05/2015
Active Rigs5864583474

RBN Energy: why Enterprise's offshore crude export terminal reached FID.
The news has been out for a few days now: Enterprise Products Partners announced last Tuesday, July 30, that, thanks to new agreements with Chevron, the midstream company has made a final investment decision to proceed with its Sea Port Oil Terminal (SPOT) about 30 miles off the coast of Freeport, TX, pending regulatory approvals. Being out front on this is critically important; even with significant growth in crude oil export volumes through the early 2020s, only one or two new export terminals capable of fully loading Very Large Crude Carriers (VLCCs) are likely to be needed. What was it that enabled Enterprise to move first among a wave of proposed projects? And what does that tell us about the VLCC-ready export terminal projects being advanced by others? Today, we look at the SPOT project and the important roles that existing pipeline and storage infrastructure play in export terminal development.
All indicators point toward sharply higher crude oil exports from Gulf Coast terminals over the next few years. U.S. production now averages more than 12 MMb/d; domestic refineries can’t use any more of the light sweet crude that major U.S. shale plays are producing in record volumes; new oil pipeline capacity from the Permian and the Cushing, OK, crude hub to the coast is coming online; and — while marine docks in Texas and Louisiana can handle current export flows (an average of 2.5 MMb/d so far this year, according to RBN’s Crude Voyager report) — they may soon be overwhelmed if more export capacity isn’t added. We’ve been discussing all this in a number of blogs over the past year or so, where we looked at the new terminals being proposed (most of them in deep water off the Texas coast) to fully load VLCCs — those deep-draft, 2-MMbbl behemoths that many shippers prefer for long-distance crude hauling because of their economies of scale. (We updated that series in early July with a look at two recent entrants in the race to build VLCC-ready export facilities: Sentinel Midstream’s Texas GulfLink project in the waters off Freeport, TX, and Phillips 66’s proposed Bluewater Texas Terminal off Corpus Christi.)
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