Kraken Bigfoot Wells: Three-Section, Extended Long Laterals, 90 - 105 Stages; 15 - 23 Million Lbs Proppant

The original note regarding the Kraken Bigfoot wells is here, but that page will no longer be updated. The Kraken Bigfoot wells will now be tracked here.

Halo effect: see this post for wells positively impacted by the Bigfoot wells. 

The Kraken Bigfoot wells came off confidential list, January 9, 2020.

The wells, triple-section; extended long laterals; 1920-acre spacing except for the section line well (3,840-acre spacing / 6 sections):

• 36013, 1,564, Kraken, Bigfoot 23-11 4TFH, 90 stages; 23.07 million lbs; Sanish, t7/19; cum 265K 3/20; a 41K month;
• 36012, 1,748, Kraken, Bigfoot 23-11 3H, 105 stages; 15.44 million lbs; Sanish, t7/19; cum 282K 3/20; a 53K month;
• 36011, 902, Kraken Bigfoot23-11 2TFH, 90 stages; 23.07 million lbs;Sanish, t7/19; cum 206K 3/20; a 31K month;
• 36010, 860, Kraken, Bigfoot 23-11 LW 1H, 105 stages, 15.44 million lbs, Sanish, t7/19; cum 252K 3/20; a 46K month; spacing: 3840-acre; 

The four wells above run from the south to the north, through three sections. The nine wells are producing wells and are in close proximity to the Bigfoot wells. In seven cases, the laterals parallel the Bigfoot wells for at least one section, generally two sections.

• 17812, 660, Kraken, Anderson 11-14H, Sanish, t6/09; cum 353K 3/20; huge jump in production;
  
• 21381, 1,150, Kraken, Dinwoodie 11-14H, Sanish, t1/12; cum 277K 3/20; huge jump in production;
  
• 28025, 442, Kraken, Donnie 11-14H, Sanish, t9/14; cum 277K 3/20; no demonstrable change after Bigfoot wells fracked;
• 22429, 743, Kraken, Reynold 11-14H, Sanish, t6/12; cum 270K 3/20; nice jump in production;
  
• 30612, IA/461, Sinclair, Uran 5-15H, Sanish, t5/17; cum 270K 3/20;
• 31470, 602, Sinclair, Uran 6-15TFH, Sanish, t8/19; cum 44K 3/20;
• 22853, 687, Kraken, Isaac 11-23, Sanish, t7/12; cum 150K 3/20; small but definite jump in production.

These two wells are not parallel to the new Bigfoot wells:

• 22563, the lateral is 90-degrees to the new Bigfoot wells, 704, Kraken, Hukkanen 11-23, Sanish, t6/12; cum 171K 3/20;
• 16953, the lateral is 45-degreess to the new Bigfoot wells, IA/440, Kraken, Fladeland 11-15, Sanish, t4/09; cum 259K 9/19; off line 10/19; remains off line3/20;

The graphics:

Production data and further information for these wells posted here.

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Production

• 36013, Three Forks:

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	11-2019	29	37623	37777	40207	59624	15747	40162
BAKKEN	10-2019	30	40902	41173	54144	62575	15075	45636
BAKKEN	9-2019	29	40351	40460	62644	60405	13596	46594
BAKKEN	8-2019	28	37217	36750	59065	36994	21478	15320
BAKKEN	7-2019	17	15052	14784	24198	14961	30	14750

• 36012, middle Bakken:

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	11-2019	30	37981	38200	27619	55326	19489	31498
BAKKEN	10-2019	30	48444	48853	36045	59850	17753	39977
BAKKEN	9-2019	30	53571	53702	52246	57643	18345	39075
BAKKEN	8-2019	29	48675	48099	55506	48869	27591	21078
BAKKEN	7-2019	17	21625	21239	26285	21711	43	21483

• 36011, Three Forks:

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	11-2019	29	30441	30545	66720	32354	10868	18779
BAKKEN	10-2019	29	30591	30759	76275	31398	10286	19710
BAKKEN	9-2019	26	28330	28045	75995	23400	8235	14967
BAKKEN	8-2019	27	7456	7432	59580	7494	4005	3297
BAKKEN	7-2019	14	6986	6861	22519	7021	14	6839

• 36011, middle Bakken:

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	11-2019	30	45914	46050	48415	63109	17535	41626
BAKKEN	10-2019	29	43934	44100	52577	58142	15290	40948
BAKKEN	9-2019	29	35856	35341	74013	47222	11001	36006
BAKKEN	8-2019	3	1536	1619	4337	1522	310	1193
BAKKEN	7-2019	14	6450	6335	19380	6392	13	6218

Mega-Fracks -- Slawson -- December 27, 2019

Years ago, maybe four years ago, maybe longer, we talked about 60-stage fracks as being huge. I don't remember if I talked about anticipating 94-stage fracks. Things just move too quickly in the Bakken. Sometimes. 

The wells:

• 32274, 2,117, Slawson, Submariner Federal 2 SLH, 31 stages; 2.6 million lbs; 63 stages; 13.8 million lbs; Big Bend, t6/19; cum 73K 10/19; 
  
• 32276, 433, Slawson, Gobbler Federal 4-26-35MLH, 46 stages; 9.6 million lbs; 46 stages; 9.8 million lbs; Big Bend, t6/19; cum 20K 10/19; 
  

Random Update Of MRO Mega-Fracks -- October 22, 2016

The IPs for these wells were posted earlier but the frack data had not yet been posted. The frack data is now posted. Check out the amount of proppant used in these wells:

• 31057, 3,490, MRO, Chamaine USA 14-35TFH, Antelope, Sanish, 45 stages, 12 million lbs, t6/16; cum 131K 8/16 after just three months;
• 31058, 3,661, MRO, Clarks Creek USA 14-35H, Antelope, Sanish, 45 stages, 18 million lbs, t5/16; cum 143K 8/16; after just 3.5 months;
• 31061, 2,942, MRO, Juanita USA 13-35H, Antelope, Sanish, 40 stages, 12 million lbs, t7/16; cum 115K after just 2.5 months;

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Mr Sandman  

Mr Sandman, Bring Me A Dream, The Chordettes

Filloon Update On Mega-Fracks In McKenzie County (North Dakota Bakken); An RBN Energy Update On The Dakota Access Pipeline -- August 15, 2016

Filloon Bakken Update: Mega-fracks in northeast McKenzie County average over 200,000 bbls of oil in first 12 months of production. Summary:

• Northeast McKenzie County is one of the best oil producing areas in the Bakken and Mega-Fracs have been producing excellent results.
• Low oil prices have motivated operators to move to better well designs in hopes of improving well economics.
• When calculating production data, it is very important to use producing days and not calendar days as it skews results.
• The expansion of Mega-Frac usage is not only being seen in the Bakken, but all major US oil producing plays.

His analysis begins:

We recently published an analysis of wells completed in ND using more than 8 million pounds of proppant. We have since expanded our findings to wells completed using 6 million or more pounds. We have also broken data down by middle Bakken and Three Forks locations. This data only encompasses wells completed through July of 2016. We are currently working and plan to release data that is more up to date in the coming months. This will help to provide a better idea of current completions and how well design and production have changed over those quarters. Results have gotten better over the past year, as operators continue to improve source rock stimulation.

There is a total of 407 Mega-Fracs in North Dakota. This includes all wells completed in the Bakken/Three Forks. The data was compiled using Welldatabase.com and Hartstreet LLC's data on proppant and fluid volumes.

And his conclusions:

In summary, Mega-Fracs are not only increasing in number, but production continues to improve. In higher pressure areas, Mega-Fracs see larger improvements. Lower well costs have motivated operators to improve well design. Lower oil prices have helped to push operators to increase this completion design over a larger number of locations. The increased production per location is partly due to highgrading. This isn't the entire reason, as better well designs have contributed. Mega-Fracs also decline at a slower rate than older completion methods. This is why US oil production has remained higher for longer than analysts expected. This is part of the reason oil prices and the US Oil ETF have remained at lower levels for this long. Northeast McKenzie County may be the best acreage in North Dakota. Middle Bakken Mega-Fracs completed over a year-and-a-half ago are producing more than 200,000 BO in the first 12 months of well life. Operators continue to state that well results are improving. Current Mega-Fracs could be producing 30% to 50% better, than the locations analyzed in this article. We will see if this estimate is correct in 12 months.

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Active rigs:

	8/15/2016	08/15/2015	08/15/2014	08/15/2013	08/15/2012
Active Rigs	32	74	194	185	203

RBN Energy: update on the Dakota Access Pipeline, the northern leg of the Bakken Pipeline System.

Sounds like the Bakken. From Emergent Group:

Diamondback recently completed their first three well pad in Howard county which targeted the Lower Spraberry, Wolfcamp A and Wolfcamp B. The company plans to begin frac operations on the second three well pad this month, all with 10,000 foot laterals and has a third pad planed for the fourth quarter all in Howard county.

Diamondback entered into the Delaware basin in July with the announcement of the company’s acquisition of 19,180 net acres in Reeves and Ward county for $560 million. This adds 290 net identified horizontal locations to their Permian inventory with the possibility of down spacing in the future. This acquisition increased Diamondback’s acreage footprint in the basin by 22% while adding infrastructure like tank batteries, frac pits and pipelines. The company is expecting to add one rig to the area in 2017.

Iraq appoints new oil minister in major cabinet reshuffle.

An OPEC deal is a tough task; expectations are high. Reuters. Regardless of what happens now or in the next six months or the next year, four years from now, Saudi Arabia is either broke or we see oil significantly higher than $100/bbl.

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The Market

Mid-day: headline says "stocks hit record highs."

The benchmark S&P 500 and the Nasdaq composite broke above previous intraday highs of 2,188.45 and 5,238.54, respectively, shortly after the open. The Dow Jones industrial average also posted a record high, rising past its previous high of 18,638.34. These records were all set last week, despite the indexes posting just slight weekly gains.

Opening: surges 85 points in early trading. Oil up over 2% and now above $45. Russia says it will work with Saudi Arabia to "stabilize" prices. NYSE --

• new highs: 163, including Encana, Enerplus, Newfield Exploration, Pioneer Natural Resources, PB, Rosetta Stone
• new lows: 9, including Noble Energy (NE), and Ruby Tuesday (RT)

Notes From Mike Filloon's Most Recent Seeking Alpha Article On The Bakken And Mega-Fracks -- July 27, 2015

I type this stuff out to help me remember; much (most) of it is taken directly from article. There will be factual and typographical errors. Readers should read the original article; these notes are only to help me understand the Bakken. The shorthand used is for my use and may be confusing to readers.

Data points from the article:

US holds resilient at 9.5 million bopd; production is a continuing debate between bulls and bears.

Production bulls believe in high-grading and well design.
Production bears believe horizontal production will fall because higher prices are needed.

But: if there are fewer completions and decline rates are high, why hasn't production tanked? Newer well decline rates are very low and cannot be compared to historical averages.

Repeat: Newer well decline rates are very low and cannot be compared to historical averages.

Three-peat: Newer well decline rates are very low and cannot be compared to historical averages.

When oil prices fell, operators moved quickly. Exploratory programs decreased (ceased?) and rigs focused on core acreage.

Core acreage:

• Bakken: Nesson Anticline
• Eagle Ford: Gonzales and Karnes
• Permian: Midland County

Operators took the rigs still under contract, drilled wells as fast as they could, but did not complete them: this left a huge "fracklog" of 4,000 to 5,000 wells. Last year the fracklog was just 400 to 800. In the Bakken alone, the fracklog rose to 925 two months in a row, April and May, 2015.

Filloon says that the US is not alone: production increases continue in Iraq, Saudi Arabia, and the UAE. My comment: on a percentage basis, the increase in Saudi Arabia is very, very small (1%) despite a 5-year, $35 billion program announced in 2012. And much of the Saudi production increase is needed for a) domestic consumption; and, b) for its new refineries, nearing 1 milliion bopd cpacity.

Filloon then lists the usual litany of global bearish factors.

Filloon says the following areas are economic at today's prices:

• core areas in the Permian, Bakken, Eagle Ford, Powder River Basin, and the Niobrara

Filloon suggests defaults may occur. Operators with no core acreage will have issues.

Filloon then discusses well design improvements. Over the past two years:

• 9,000-foot, 30-stage laterals
• three million lbs proppant, 50,000 bbls of fluids

Now, huge frack jobs:

• 50+ stages, 6+ million pounds of sand
• 100,000 bbls of frack fluids
• some jobs are much bigger
• Other factors:
• communication: adjacent wells increase production
• sand heavy fracks are increasing production faster than expected

Get this:

well production from core areas can out-produce marginal areas up to 500%
on average, it is closer to 300% but it depends on the areas used for comparison

Filloon spends a lot of time on the issue of communication.

Filloon gives the EOG experience, which has been previously discussed.

Then CLR, the Salers Federal 3-27H well:

• 50-stage, long lateral
• 312,000 bbls of frack fluid
• 18 million+ lbs of sand plus 1.2 million lbs ceramic
• of the seven wells on the Salers Federal pad, only three are producing
• the four that are not producing, are part of the fracklog
• in nine months: $11 million in revenue at $60/bbl and $3/Mcf
• 172,950 bo; 207,820 MCF
• although the Salers Federal 3-27H produced very well, it stimulated production elsewhere

Filloon also noted that there is almost no depletion; the well produced for a whole year and is still producing almost 20,000 bbls/month of crude

• essentially, we may be seeing re-fracking of portions of neighboring wells

Filloon even suggests there may be communication across source rock; from the middle Bakken to the Three Forks.

Filloon then talks at length about QEP, the Grail field, and the Moberg wells. It is improtant to note that the Moberg is not QEP's newest well design.

Risk: if an operator were to drill too close to another well for the purpose of frackign into a well nearby, it could ruin the reservoir. This could significantly decrease or stop production from all wells effected. The hope is to increase the estimated reserves of the well by re-opening fracks that have closed or opening new fissures.

High Oil Production, Low-Price Environment Due To Bakken Mega-Fracks -- Mike Filloon -- July 27, 2015

Tweeting now: US gasoline price ($2.75) at 10-week low, diesel ($2.72) lowest since Oct 2009.

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Mega-Fracks

This article will no doubt be archived by SeekingAlpha.  I've also posted lengthy notes on this article to help me understand the Bakken.

The summary bullets:

• lower rig and completion numbers have not caused a rollover in U.S. oil production
• marked improvements in well design plus high-grading have been very effective in producing more resources per foot
• mega-fracs are also increasing production in adjacent wells through communication
• given the change in U.S. oil well economics, we may need to retest 52-week lows to get meaningful production off the table
• new well designs have changed the current decline curve, further skewing U.S. production estimates

There are more reasons, but these are the general beliefs. If fewer completions are occurring and depletion rates are high, why has production not rolled over? Many of the reasons are well known, including high-grading and lower oil service costs. Newer well designs skew data as depletion continues to decrease.

This cannot be emphasized enough, newer well decline rates are very low and cannot be compared to historical averages. Recent completions also produce more oil. When oil prices fell, operators moved quickly.

Exploratory programs decreased and rigs focused on core acreage. This includes the Nesson Anticline of the Bakken, Gonzales and Karnes counties of the Eagle Ford and Midland County of the Permian. There are other areas, but this provides a general idea of current core plays.

The Tuscaloosa and Eaglebine have suffered, as payback times can take several years.

Operators had rigs under contract, so they did what they do best. They started drilling holes. By moving quickly, they were able to add locations waiting on completion. Operators planned to let the rigs go after the contracts were up.

This left a huge "fraclog" of 4,000 to 5,000 wells. Wells drilled but not completed are considered part of an operator's inventory. By waiting, completion costs decrease, as do well costs. An operator may wait for higher oil prices. Last year the fraclog average was just 400 to 800.