More On That XTO "POW" Well; Monitoring Communication Between Two Upper Benches Of The Three Forks -- February 11, 2020

The well:

• 36679, drl, XTO, Mariner 14X-36POW-S, Bear Creek, Three Forks 2B / 1B;
  

See #18797 at this post. "Equivalent to a new well being drilled."

From the file report, #36679:

• the purpose of this well is to monitor fracking communication based on proximity to offset wells being fracked
• this well is strategically landed below the Mariner 14X-36D (#36678), the wellbore traversed from the lower section of the Three Forks second bench to the lower Bakken shale
• special fiber optic liner was run to monitor fracking communication from the Mariner 14X-36D
• the Mariner 14X-36POW-H proved the most useful offset well in predicting formation tops
• data was used to "pin-point" a strategic landing of the subject well;
• curve successfully landed 28' below the top of the Three Forks second bench
• reached TD, 16,890' MD on October 10, 2019
• low gas units throughout the second bench
• the greatest hydrocarbon shows (C1-C4) preferentially occurred in the more dolomitic horizons of the Three Forks first bench; background gas decreased to an approximate range of 25 - 50  units in the second bench;
• the objects of drilling the lateral was to create a straight wellbore that traversed from the Three Forks second bench to the Three Forks first bench to be used as an observation well;
• entry into the Three Forks first bench was noted by a distinguishable claystone at the bottom of the formation; the approach toward the Pronghorn was noted by siltstone and limestone in samples;
• the vertical, curve, and lateral were drilled in 18 days using seven bottom-hole assemblies;
• the wellbore was completed 100% within the Three Forks second bench and Three Forks first bench target interval, opening up 4,963' of formation to be used to monitor offset well fracking communication;
• permit: spacing: 640 acres; section 1-147-96; Three Forks B2;
• surface hole: SWSW 36-148-96, 108FSL, 187 FWL;
• bottom hole: SENE 1-147-96; 1530 FNL, 102 FEL;

Graphics:

The BR Mathistad Wells In Croff Oil Field

Locator: 10010MATHISTAD.

 

Updates

 September 4, 2024: compare today's map with the original map --

January 14, 2018: see first comment. A reader has really made some interesting observations, including a great link.

Just a couple notes of interest:

The lateral for the Mathistad 2-35H runs 50 feet above and parallel to the 1-35H. It was originally owned by Continental Resources and was an experimental well partially funded by the State of North Dakota to determine possible communication between nearby laterals most notably the 1-35H. The details are on the attached link:

https://www.rigzone.com/news/oil_gas/a/79041/Continental_Reports_Successful_TwoReservoir_Test_in_Bakken_Shale

Also, there looks to be room for another 4 well pad between the new and older wells? 

And, then, of course, my reply: yes, there is more than enough room for another 4-well pad between the older well pads, and then, of course, vertically, additional benches in the Three Forks, possibly.

With regard to communication between formations, see this post: http://themilliondollarway.blogspot.com/2010/02/communication-between-formations.html, February 7, 2010.

Also, this post from May 4, 2011.

Also, a "fracturing question," March 3, 2011.

Original Post 

Note production profile of two older Mathistad wells, scroll down to bottom of post. 

The Mathistad wells:

• 16983, 15 (no typo), BR, Mathistad 1-35H, Croff, API: 33-053-02852, t6/08; cum 321K 11/19; was off line 6/19; returned to production, 9/19; cum 380K 6/24; off line;
  
• 18013, 842, BR, Mathistad 2-35H, Croff, API: 33-053-03011, t7/09; cum 281K 11/19; cum 337K 2/24; off line;
  
• 33144, 318, BR, Mathistad 22A MBH, Croff, 30 stages; 10.5 million lbs, t10/17; cum 476K 11/19; cum 766K 7/24;
  
• 33146, 273, BR, Mathistad 22B UTFH, Croff, 4 sections, Three Forks, 31 stages; 15 million lbs, t10/17; cum 493K 11/19; cum 702K 7/24;
  
• 33152, 414, BR, Mathistad 6-8-35 MBH, Croff, 29 stages; 10 million lbs large, t11/17; cum 562K 11/19; cum 791K 7/24;
  
• 33150, 655, BR, Mathistad 3NC-MTFH, Cross, 4 sections, Three Forks, 29 stages; 14.5 million lbs, t11/17; cum 466K 11/19; cum 633K 7/24; off line;
• 33155, 40, BR, Mathistad 7-8-24 MBH,t3/20; cum 381K 7/24;
  
• 37580, conf, BR, Mathistad 2A MTFH, no production data,
  
• 37578, conf, BR, Mathistad 2B MTFH, no production data,

The graphic:

Recent production for two older wells:
16983:

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	11-2017	15	3277	3289	508	2839	2802	0
BAKKEN	10-2017	1	0	0	0	0	0	0
BAKKEN	9-2017	0	0	0	0	0	0	0
BAKKEN	8-2017	23	894	685	286	1558	1501	0
BAKKEN	7-2017	30	1136	1109	256	1977	1903	0
BAKKEN	6-2017	30	1156	1349	196	1928	1854	0
BAKKEN	5-2017	31	1132	905	228	2111	2034	0

18013:

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	1-2018	11	1776	1638	336	1728	1701	0
BAKKEN	12-2017	27	5528	5169	958	5814	5747	0
BAKKEN	11-2017	15	3024	3084	621	2899	2862	0
BAKKEN	10-2017	0	0	0	0	0	0	0
BAKKEN	9-2017	0	0	0	0	0	0	0
BAKKEN	8-2017	11	411	597	44	847	822	0
BAKKEN	7-2017	31	1461	1350	213	2897	2820	0
BAKKEN	6-2017	30	1449	1597	141	2573	2499	0
BAKKEN	5-2017	31	1575	1586	165	2675	2598	0
BAKKEN	4-2017	28	1788	1576	170	2305	2235	0

16983:

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	1-2018	31	6003	5930	1024	6635	6558	0
BAKKEN	12-2017	31	6246	6280	1621	7012	6874	61
BAKKEN	11-2017	15	3277	3289	508	2839	2802	0
BAKKEN	10-2017	1	0	0	0	0	0	0
BAKKEN	9-2017	0	0	0	0	0	0	0
BAKKEN	8-2017	23	894	685	286	1558	1501	0
BAKKEN	7-2017	30	1136	1109	256	1977	1903	0
BAKKEN	6-2017	30	1156	1349	196	1928	1854	0

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.