Tuesday, December 26, 2017

How's That Renewable Energy Working Out In New England? -- December 26, 2017

A reader alerted me to this. I had seen it earlier but I was not going to post it until I saw this story: the day after Christmas, 75% of US sees freezing temperatures, and it's particularly severe in New England, which naturally led to the next question, "how's that renewable energy working out to keep the heat on?"



Spot prices for electricity surging above $200/MWh. And so it goes. Surrounded by a glut of natural gas and electricity surging above $200/MWh. CAVE dwellers don't want natural gas pipelines.

WTI Hit "$60" Today -- December 26, 2017; Hillary Aghast!

Active rigs:

$59.8012/26/201712/26/201612/26/201512/26/201412/26/2013
Active Rigs534162173186

No new permits.
 
Three permits renewed:
  • EOG: three Parshall permits, all in Mountrail County
No permits cancelled.

DUCs reported at completed: none.

Hillary aghast? See this site. In case this link breaks, the issue -- US government looks to subsidize coal industry.

Random Update Of MRO's Kukla Well, #16422 -- December 26, 2017

Updates

March 20, 2018: see long note below. Production has been updated for #16422:

PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare
BAKKEN1-2018311351513443190661323211279158
BAKKEN12-20173115498157562357614411124180
BAKKEN11-2017281782617771308271339675523770
BAKKEN10-2017269433939022877667440641461
BAKKEN9-201719107971018282291280631078468
BAKKEN8-20170000000
BAKKEN7-20170000000
BAKKEN6-20170000000

Original Post
 
Disclaimer: in a long note like this there will be typographical and factual errors. It is difficult to separate opinion from facts. I may be seeing things that do not exist, and I certainly see things differently that a lot of analysts. 

Case study: as you go through this case study, think about this. Some folks are suggesting that operators are running out of new drilling locations in the "sweet spots" in the Bakken. I don't buy that. To some extent, "sweet spots" are defined by the price of WTI. Whatever.

The bigger story is continued management of existing wells. Somewhere else one can find the exact number of Bakken wells that have been drilled and are still being "managed." I come up with about 10,500 Bakken wells. The vast majority of those wells have not been re-fracked, either with a mini-re-frack, a modest re-frack, or a full-fledged re-frack.

If one considers an existing Bakken well as a well that could be re-fracked, one could argue it's a "new" drilling location. That may not make sense, but think about it as you go through this case study. This makes unconventional (tight oil) very different from conventional oil.

The well:
  • 16422, 293, MRO, Kukla 34-34H, Murphy Creek, F; t12/07; cum 141K 10/17;
Recent production profile:

PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare
BAKKEN10-2017269433939022877667440641461
BAKKEN9-201719107971018282291280631078468
BAKKEN8-20170000000
BAKKEN7-20170000000
BAKKEN6-20170000000
BAKKEN5-20170000000
BAKKEN4-20170000000
BAKKEN3-2017134437473264350336
BAKKEN2-20172815021873462146101132
BAKKEN1-20173122212101705209801674
BAKKEN12-20161247806602400120
BAKKEN11-20160000000
BAKKEN10-20160000000

It has been off-line since 1/15:

BAKKEN12-201431954926315809360161
BAKKEN11-201430976939361759360115
BAKKEN10-2014311001114034367028394
BAKKEN9-201430994906347630244100
BAKKEN8-20143110731129372884432151
BAKKEN7-2014311139111842274234886
BAKKEN6-20143011621122443685233148
BAKKEN5-20143113381611570747232186

Initial production after original frac:

BAKKEN9-20083024502433707154615460
BAKKEN8-20083129183008838195819580
BAKKEN7-200831318431241043200420040
BAKKEN6-200830411342791197274927490
BAKKEN5-200831462743711523254325430
BAKKEN4-200818177418218629319310
BAKKEN3-20083131973218808159015900
BAKKEN2-20082937553766914177017700
BAKKEN1-200829503051761307230923090
BAKKEN12-200731580052192915228022800

FracFocus:
  • Re-fracked 7/24/2017 - 8/10/2017; 6,706,365 gallons of water; water, 91% by mass; 
  • a gallon of water weighs: 8.345404 pounds
  • 6,706,365 gallons x 8.345404 pounds = 56 million pounds
  • 91% of what = 56 pounds
  • 61.5 million pounds - 56 million pounds = 5.5 million pounds proppant max
  • let's see if there's sundry form over at NDIC
  • wow, there is
  • the new IP: 1,742 (crude oil)
  • 45 stages
  • and, the amount of proppant? 5.3 million lbs (whoo-hoo, the math above was right on target)
The other two wells in the drilling unit unremarkable at this point: #25761 and #25760, although the latter was off-line 10/17; it's not a great well, and wonders if this one might be a candidate for a re-frack?

The graphic:


Comments:
  • this well was, in the big scheme of things, a pretty lousy well from the beginning; the IP and total production the first couple of years was not all that great
  • it was shut in for almost two  years
  • it was then re-fracked, and by "modern" standards, it was re-fracked with a small amount of proppant, 5.3 million pounds
  • the modest re-frack resulted in an IP and a first two-month production well above what the well produced when it was first drilled/fracked back in 2007
  • the operator had almost no risk re-fracking this well
  • the well was already drilled; no new infrastructure costs were incurred; no new lease money; no new nothing as far as costs, except the costs associated with a modest re-frack
  • my hunch is that the geologist/company could almost "guess" what new production would be based on their knowledge of the Bakken
  • finally, note that this well is almost ten years old, and is still flowing, without a pump, at least according to the scout ticket; sometimes the scout tickets are wrong
  • could one consider this a "new" drilling location? Just saying
  • one more thing: note that is an MRO well; it's my feeling that MRO is taking the lead on re-fracks

October, 2017, US Crude Oil Production Data To Be Released Later This Week -- Richard Zeits -- December 26, 2017

EIA to report US crude oil production for October, 2017, at the end of the week. Richard Zeits forecast and my comments:
  • 9.45 million bopd; above the 9.28million bbls/day implied by the EIA's weekly estimates
  • Zeits reminds us that October, 2017, production was strongly impacted by Hurricane Nate
  • Zeits again wades into the controversy regarding EIA forecasts
  • oil peak folks think the EIA is overly bullish
  • Zeits thinks EIA may be under-estimating the oil industry
  • the best "news": unless I missed it, Zeits did not mention rig count; CNBC was still emphasizing rig count as the best way to measure/forecast US crude oil productivity

How Bad Was The Saudi Trillion-Dollar Mistake? -- December 26, 2017

It will take them more than a decade to balance their budget. 

From Bloomberg:
  • Saudi assumes: oil revenue will surge by 80% by 2023 -- that's five years from now; and almost ten years from when Saudi first announced plans to flood the world with oil, to crush US shale (their trillion-dollar mistake)
  • six-year program to balance the budget
  • their plant assumes rising oil prices and increasing output: will push oil sales to 801.4 billion riyals ($214 billion) from 440 billion riyals this year
  • assumes the price of oil will reach $75 (when that happens is not provided)
  • one expert says these assumptions look very "challenging"
  • "the strong oil revenue growth in 2017 will be difficult to repeat"
  • forecast: oil production to 11.03 million bopd vs an average 10 million bopd
  • for 2020: 10.45 million bopd
From another story earlier this month, this is how the Saudi's plan to execute their budget:


Random Note Regarding A Dry Well In Newporte Oil Field -- December 26, 2017

This well was reported as dry today:
  • 33289, dry, Armstrong, Hanson 33-43, Newporte, Cambro/Ordovician, no production data, 
This is from the summary at the file report:
This well was drilled on the outer rim on the west side of a seismically-defined meteor impact crater. Production has been established in two wells; one on the eastern side of the crater, and on the southwestern side of the crater. Both of these wells are completed in the Deadwood Sand.

This well, unfortunately, found no Winnipeg Sand. Just below the Winnipeg Shale is a tight sand identified as Deadwood Sand. There was no show in this sand. The Winnipeg Sand is quite pyritic; it usually appears as medium grained sand with pyrite filling the interstices. [The geologist] referred to the Winnipeg Sand as chrome plated -- that is what it looks like: clear quartz grains protruding through the silvery pyrite. Therefore I believe that the Winnipeg Sand is absent her, and the sand present is Deadwood Sand. 
And then this:
The depths reported by the driller and the logger differ by 56 feet. This could be due to mis-counting drillpipe (2 joints). [The geologist] believes a more likely explanation lies in the abandonment of magnetically marked cables on the wireline truck. This results in depths measured by the logger being less than that reported by the driller. There was fill in the hole; during the latter part of the hole [the geologist] observed black shale cleats up to 1" by 1 1/2'  x 1/2'. The up-hole shales were sloughing in irregular timed pulses. The logger (wisely) did not spud the tool on bottom. [The operator} was in and out of the hole several times whilst waiting for a logging truck to get to location, and [the geologist] cannot image the rig crews mis-counted the drillpipe the same way every time. [The geologist] thinks the presence of ill, and the known error in depth measurements by logging companies since abandonment of marked cables can account for the discrepany in the depths reported by the driller and the logger.

The Market And Energy Page, T+339 -- December 26, 2017 -- TSLA And The "Death Cross"

Wells coming off confidential list today: have been updated.

WTI: from a post early this morning --
Before the open, WTI was $58.44. Early after the opening, WTI jumped to $59.41, said to be due to a pipeline blast in Libya and  the loss of Forties oil right now.  My thoughts: the jump in price had little to do with the Forties pipeline or the Libyan story. The Forties pipeline story is not new; the pipeline has been repaired; and, already the pipeline is being tested for re-start in early January, just as the company said would happen. Libya? When do we not hear of a problem in Libya. Some might argue that WTI is headed toward $60 on a "no-news" story.  [Later: on CNBC we now learn that the pipeline blast in Libya has resulted in 90,000 bopd -- that is so inconsequential as to be laughable as a cause for the jump in the price of oil.]
API drawdown data: normally, the API reports API US crude oil inventories late in the afternoon on Tuesdays; normally I find those reports linked at this site; so far it's not on today's calendar, suggesting the report will be released tomorrow; it's my gut feeling that some folks know that data point before it's officially released and could affect the price of WTI; WTI was up significantly despite no "real" news -- a Libyan pipeline explosion removing 90,000 bopd isn't a big enough story to move the price of oil;

TSLA: earlier today, a reader sent me this link, suggesting that it will be years (decades?) before Tesla can possibly have a positive cash flow. Now this, the "death cross":

Market: whatever the reason for the jump in WTI (and Brent), the bigger story is the jump in share prices across the board in the oil sector. Whoo-hoo.

Disclaimer: this is not an investment site. Do not make any investment, financial, job, travel, or relationship decisions based on what you read here or what you think you may have read here.

NYSE, new highs and lows.
  • new highs, 168: Arch Coal (!!); CA; CAT; CVX; DE; EOG; Marathon Petroleum; OXY; Phillips 66; Shell; Statoil; UNP
  • new lows, 19
  • if you want to see another reason why Arch Coal might be doing better, see this post.
Wage disparity:

CLR Shows "Major" Improvement In Oil Production -- Filloon -- December 26, 2017

Over at SeekingAlpha:
  • CLR continues to better stimulation and increase sand and fluids usage
  • well design has increased production per foot significantly and this should continue into 2018
  • CLR is well positioned as higher oil prices and lower Bakken differential improve economics
  • Banks field has the best oil curve. It is followed by Camp, Camel Butte, and Elm Tree. Elm Tree and Sanish field account for 35 completions.
Continental Resources, Inc. has had a number of very good results in the Bakken since the beginning of 2016.
Better stimulation techniques coupled with increased volumes of sand and fluids continue to improve completions.
We pulled the production data of 88 CLR Bakken locations turned to sales after January 1 of 2016. The results were quite good. A number of locations topped 200 KBO, and one did this in seven months. Two horizontals produced over 350 KBO in 14 months. 74 of the 88 completions had laterals of at least 9,000 feet.

Global Warming Update For The Bakken -- December 26, 2017

Updates

December 26, 2017: It isn't just the Bakken enjoying global warming. Some other headlines today --
Original Post 

Most interesting: the "cold" months in western North Dakota are generally later January, and early- to mid- February. 

Today's temperatures, screenshots taken at 7:13 - 7:21 a.m., December 26, 2017, for North Pole (the Arctic); Watford City, ND (the Bakken); and the South Pole (the Antarctic):


Williston, ND:




Watford City:


North Pole:



South Pole:



Random Update Of Three Whiting/KOG Mandaree Wells -- December 26, 2017

NB: note the names of the two earlier wells; and the name of the re-fracked well.



The wells:
  • 18517, 1,595, Whiting, Two Shields Butte 2-24-12-2H, Mandaree, t9/11; cum 494K 10/17;
  • 19826, 2,945, Whiting, Two Shields Butte 2-24-12-1H3, Mandaree, Three Forks; 9/11; cum 454K 10/17; 10562; well name change from 2-24-12-1H to 2-24-12-1H3;
  • 30929, 1,989, Whiting, Two Shields Butte 1-24-12-1H, Mandaree, 44 stages, 14.6 million lbs, t1/17; cum 210K 10/17; 10476; 

18517, 2-24-12-2H:
BAKKEN10-20173149754937303616771060400
BAKKEN9-201719309431251845843252447
BAKKEN8-20172952425301319118491331295
BAKKEN7-20173164196503463031802629331
BAKKEN6-201730591758524360392723511355
BAKKEN5-201731614161024898527025082454
BAKKEN4-201730557356204750608328063001
BAKKEN3-20173161316028796145154014263
BAKKEN2-2017212451239037672064185392
BAKKEN1-2017002630000
BAKKEN12-20160000000
BAKKEN11-2016302656256111412801217343
BAKKEN10-20163133533454174943183178394
BAKKEN9-2016293920383216972884638165

19826: 2-24-12-1H3:
BAKKEN8-2017313510357579181025705156
BAKKEN7-20173154605578941433542777350
BAKKEN6-201730631062297903587335392039
BAKKEN5-201731606060367924760136373559
BAKKEN4-201730617962278171708232743501
BAKKEN3-20173166756640921350374487294
BAKKEN2-20172857265595737460925564275
BAKKEN1-201753014192191441280
BAKKEN12-20160000000
BAKKEN11-201615130813507695003657


30929, 1-24-12-1H:
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare
BAKKEN10-2017312005720038950518790124894717
BAKKEN9-2017302141621451100481637752049228
BAKKEN8-20173124001240831151324035180634000
BAKKEN7-2017312060120521878918889160062017
BAKKEN6-201717964997203482853651912991
BAKKEN5-201731169651692882261987795849377
BAKKEN4-20173018717189568904218381018110888
BAKKEN3-20173123713238561093318502167071094
BAKKEN2-20172831180313832785222159204451011
BAKKEN1-20172524057230782463315942157700



Random Production Update For An Armstrong Lodgepole Well In Southwest North Dakota -- December 26, 2017

I track this well at this post. This page will not be updated. Random update of production data for this well:
  • 18496, 474, Armstrong Operating, Gruman 18-3, Patterson Lake, t3/10; cum 740K 10/17;
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare
LODGEPOLE10-20173110652106120447443310
LODGEPOLE9-201730876186380367935410
LODGEPOLE8-201724608862680257624660
LODGEPOLE7-201731789977162333631930
LODGEPOLE6-201730748576717309829600
LODGEPOLE5-201731764474587305029070
LODGEPOLE4-201730739274686291627780
LODGEPOLE3-2017317652787910289027470
LODGEPOLE2-2017286980687311267425450
LODGEPOLE1-2017317864785111303728940
LODGEPOLE12-201630795478718313629980

Random Update Of Re-Fracked QEP Wells -- December 26, 2017

Back on October 28, 2017, there was a post discussing recent comments by QEP on re-fracking. In that post:
Likely candidates, all in Heart Butte (there may be other candidates) :
  • 20964, 1,035, QEP, MHA 1-32-33H-148-92, Heart Butte, t1/12; cum 265K 9/18;
  • 20965, 810, QEP, MHA 3-32-33H-148-92, Heart Butte, t1/12; cum 168K 9/18;
  • 23093, 2,052, QEP, MHA 3-06-31H-150-92, Heart Butte, t9/13; cum 449K 9/18;
  • 23097, 2,512, QEP, MHA 2-06-31H-150-92, Heart Butte, t9/13; cum 486K 9/18; (see production profile below); according to FracFocus (API 33-025-01754), fracked in 2013; and re-fracked 6/18/17 - 6/29/2017;
  • 24209, 2,854, QEP, MHA 5-04-33H-150-92, Heart Butte, t5/13; cum 334K 9/18;
At the time, the data for several of the wells above was not provided, but it has now been updated.

I have long forgotten how those five candidates were chosen as candidates for re-fracking. I assume it came from going through the production profiles of producing wells in Heart Butte.

So, let's look at the last 10 months (or so) of production from each of those wells:

20964, API: 33-025001394:
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare
BAKKEN10-201731453244336151236765261
BAKKEN9-2017304293425660552739799546
BAKKEN8-2017294051449456091759696194
BAKKEN7-2017303676357065642288860
BAKKEN6-20173052485156853829357760
BAKKEN5-201727538455957252325610900
BAKKEN4-201730579254678298489831700
BAKKEN3-2017316845687910363563736990
BAKKEN2-2017287218726713092599536970
BAKKEN1-2017227814792512121455628540
BAKKEN12-20162793749062166556102411020
BAKKEN11-201630102841036120908657045730
BAKKEN10-20163112254125643249072355090288
BAKKEN9-2016298839890029626488033270
BAKKEN8-2016275260531130430252911520
BAKKEN7-2016315601647689033446
BAKKEN6-20169340223570773243
BAKKEN5-201629112911211323152800

20965, API: 33-025-01395:
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare
BAKKEN10-201725151815542809141533331
BAKKEN9-2017302848283154231549446304
BAKKEN8-2017312860274269321606636177
BAKKEN7-20171322559741510
BAKKEN6-20172023432406541514673780
BAKKEN5-20172737354095870714934340
BAKKEN4-2017305978563314205500032450
BAKKEN3-2017316853679616577510133250
BAKKEN2-2017285298522013896248713900
BAKKEN1-2017173442327111827238914460

23093, API: 33-025-01750:
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare
BAKKEN10-20173117354173951627420966568514880
BAKKEN9-2017302217622122271122615092425185
BAKKEN8-20173121753217064654524159921014867
BAKKEN7-2017104762465818822402121391800
BAKKEN6-201700420000
BAKKEN5-20172218181717665137801069
BAKKEN4-2017161659198443719711121526
BAKKEN3-201731387637858034564403797
BAKKEN2-201728336233188283732330052
BAKKEN1-2017314254424972647443888435

23097, API: 33-025-01754:
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare
BAKKEN10-2017311424314242946114859399410457
BAKKEN9-201730164721651586601903267318318
BAKKEN8-2017312070920755919219800755812201
BAKKEN7-201713576156489788507726832258
BAKKEN6-201700530000
BAKKEN5-20171822982371522266302405
BAKKEN4-20173038643948879433126701253
BAKKEN3-201731394338107933993346383
BAKKEN2-201726310130319003098270943
BAKKEN1-2017263562364587436742989334

24209, API: 33-025-01949:
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare
BAKKEN10-201718980097613824891507094
BAKKEN9-201723121731220290621133009681
BAKKEN8-2017291614716128236091382237111383
BAKKEN7-20174217318594036150501215
BAKKEN6-201724718148113473
BAKKEN5-201727126213447831717590239
BAKKEN4-201730216721018662040733269
BAKKEN3-20173123632447933215598972
BAKKEN2-20172821642133897197186290
BAKKEN1-2017312335239410622130565398


Frack data (from FracFocus):
  • 20964, API: 33-025001394: re-frack, 7/14-27/2016;a sundry form at NDIC, re-frack 7/28/16; 30 stages; 8.3 million lbs;
  • 20965, API: 33-025-01395: re-frack, 7/14-22/2016;
  • 23093, API: 33-025-01750: frack 9/5-22/2013; re-frack 6/18-30/2017;
  • 23097, API: 33-025-01754: frack 8/30-31/2013; re-frack 6/18-29/2017;
  • 24209, API: 33-025-01949: frack 5/11/2013; re-frack 7/1-9/2017;