Monday, January 28, 2013

Devon Retains Scotia Waterous To Market TMS Position


Scotia Waterous (USA) Inc. has been retained as the exclusive advisor by Devon  to advise and assist in the sale of Devon’s Tuscaloosa Marine Shale (“TMS”) assets in Louisiana and Mississippi.

The details:
http://www.scotiawaterous.com/devon_2013_tuscaloosa/overview.html

For an explanation, see the prior post.

Sunday, January 27, 2013

Devon Energy - A TMS Post-Analysis

Over the past year, there have been many discussions regarding Devon's frac design on their TMS wells.  I commend them for being the "TMS leasing pioneer", but their operational approach has generated many questions.  With many rumors circulating regarding their status in the play, it might be a good time to perform some post-analysis.

I believe that their results can be directly correlated to the landing zone of the laterals and the amount of proppant pumped.  The log below displays the Passey Log Method where the deep induction and sonic logs separate with increasing TOC.  Across the play, the target zone typically appears 30-70' above the base of the TMS.  The wells with the best initial potentials in the play so far (Encana's Anderson 17h/18h), landed in this zone quite well.  Devon's initial wells (Beech Grove, Soterra) landed very high in the section likely due to the fact that they believed that the water bearing sands below could be an issue.  Their next four wells targeted very low in the section.  These wells should disprove the theory that the water bearing sands below are an issue.  None of their six wells landed in the highest TOC section of the TMS.  The minimal proppant levels make the probability of achieving an economic well even more unlikely.  The Richland Farms 74H-1 was the closest to the target zone and when you compare the IP30 to the 91,600 #/stage pumped, this well exhibits the most efficient, economic result.  It would be interesting to see this well offset with a higher landing target and 450,000 #/stage of proppant.  I envision 1200+ boepd.


Wednesday, January 16, 2013

EOG Applies For Additional Units

EOG has filed applications for two additional TMS units.  The Avoyelles Parish location (Marksville Field) is close to the Dupuy 20H-1.  The Vernon Parish location (Fort Polk Field) represents a rank TMS wildcat.  This location will be watched very closely by many and could prove the play to be massive in size.



Monday, January 14, 2013

Devon Tests The Austin Chalk

Devon's decision to make a vertical completion in the Austin Chalk in the Lane 64-1 well is surprising and very exciting.  It appears that the company is attempting to test additional targets on their acreage.  The Austin Chalk provides a nice secondary objective that could have regional potential.  Over the last two years, several companies have been challenged by the play in southern Avoyelles and northern St. Landry Parishes.  Anadarko and Atinum appear to have abandoned the play, while 2-man Australian company, Pryme Energy, is currently drilling a well in southern Avoyelles funded by Macquarie Bank.  The Austin Chalk, due to its fractured nature, can create many challenges during the drilling, completion, and production phases.  Mudlog shows during the drilling phase can entice operators to complete the well.  Nice initial potentials generate excitement only to rapidly drop in production the first month.  It's not a play for the timid or capitally constrained.

With regards to Devon's location, I believe that this is in an area where the existing data warrants testing.  Being proximal to the Feliciana Salt Ridge increases the probability of the presence of fractures.  Wells near the Lane 64-1 have mudlog shows in the Austin Chalk.  Log analysis (see below) indicates high resistivities and good porosities. The SONRIS work order indicates that they plan to perforate over 200'.  Locals indicate that the rig is on location.  This should be an exciting development for the area that is located in the deeper part of the TMS.  I commend Devon for their efforts.  It must seem like an eternity for the locals who had a Devon rig on the Lane 64 location back in May, 2011.  Good luck to all!
SONRIS work order

Tuscaloosa Marine Shale - activity map; Base of TMS structure

Austin Chalk production
Devon Lane 64-1: resistivity and gamma ray log (Source: SONRIS)

Passey crossover log displays for two wells adjacent to the Devon Lane 64-1



Thursday, January 10, 2013

EOG Dupuy 20H-1 - IP Discussion

I knew that when I posted the estimated economics for the EOG Dupuy 20H-1 it would generate some discussion. I have received many emails and calls about it.  The main question is why my initial potential is different from the one released on SONRIS. I posted my information on 1/4/13 prior to the SONRIS posting of the initial potential on 1/7/13.  My value of 650 bopd was provided from a good source and it closely matched the allowable that was posted on SONRIS (656 bopd on 11/30/12).  The GOR of 700 was also provided from a good source.
EOG Dupuy 20H-1 (Source: SONRIS)
From what I hear, the well has averaged close to 500 bopd over 22 days on a small choke.  If that is accurate, with a GOR of 700, the IP30 should be around 560 boepd.  That is lower than my estimate of 785 boepd made on 12/3/12.
http://tuscaloosatrend.blogspot.com/2012/12/dupuy-estimate-update.html

I've been asked by many if I think that operators release lower numbers on purpose.  The guidelines for initial potential reporting are very loose. In this play with the acreage mostly leased up, I don't see any reason for that.  The table below compares the IP vs IP30's for the wells.  There is no real trend.  In shale plays, I believe that the IP is not very important.  While it is the first data point, I believe that the first really relevant data point is the IP30.  It illustrates real production over a month.  When you compare IP's or IP30's between wells, choke size is important.


Even more important is the IP180 representing six months of production.  The Encana Anderson 17H-1 has an IP180 of 72755 BO and 23354 MCF.  The Encana Anderson 18H-1 has an IP180 of 89391 BO and 28051 MCF.  I consider those to be impressive.

My well costs of $10.3 million has also generated questions.  Daily rig rates and frac costs on a per stage basis are well known, so calculating costs is fairly straight forward.  I presented some play economics several months ago using $10.2 million.  I believe that EOG will quickly have costs below $10M on Dupuy offsets.

Those that have followed this blog since March, 2011 know that I don't post hearsay and rumors.  I prefer to post information once I feel confident that it is accurate.  I also provide technical information to support it.  There are many chat websites where you can go to get enthralled with rumors.  That is not the goal of this website.

Those that are viewing this blog to gain confidence in purchasing public stock of TMS operators are advised to do your own research and investigation.

The comment box below provides the opportunity for anyone to join the discussion.  If you're really bold, post under your real name.  Those anonymous internet names remind me of the old CB Radio handles in the 70's.  With that, I conclude with "10-4 good buddy.  I'll be 10-10 on the side".

Tuesday, January 8, 2013

Amelia Resources LLC Announces Sale of 47,300 Net Mineral Acres


THE WOODLANDS, Texas, Jan 08, 2013 (BUSINESS WIRE) -- Amelia Resources LLC today announces the sale of 47,300 net acres in the Tuscaloosa Marine Shale play.
Amelia Resources announced today that it has been retained as a technical consultant to host a data room to market 47,300 net acres in the Tuscaloosa Marine Shale ("TMS") play. The data room will open in late January with bids due the first week of March.
Entire press release:
http://www.marketwatch.com/story/amelia-resources-llc-announces-the-sale-of-47300-net-acres-in-the-tuscaloosa-marine-shale-2013-01-08

Prospect Flyer:
http://ameliaresources.com/documents/tuscaloosatrend/Amelia%20Resources%20Tuscaloosa%20Marine%20Shale%2047300%20Acres%20PROSPECT%20FLYER%20JAN%202013.pdf

Play Overview:
http://ameliaresources.com/documents/tuscaloosatrend/AMELIA%20RESOURCES%20LLC%20%20Play%20Overview%20JAN%202013.pdf



Friday, January 4, 2013

EOG Dupuy Land Co 20H-1 Economics

With some estimated costs for the EOG Dupuy Land Co. 20H-1, it is now possible to generate some economics.  While the well is EOG's first horizontal in the TMS, it potentially represents the first economical well in the play.



Eagle Ford Shale Evaluation

The Eagle Ford Shale continues to be the "darling" of the industry.  A paper was presented to the Society of Petroleum Engineers in October, 2012, that presents some interesting statistics.  Based on the current TMS results, I believe that the EUR's are very competitive.  It's interesting to note that the author concludes that the longer laterals didn't produce the best results.  EOG's TMS lateral lengths might be on track. 

Abstract 
"Although the Eagle Ford shale is early in its history, the study provides a comprehensive examination of per well recovery and decline data in the South Texas trend using the latest production information up to early 2012.  Individual forecasts of the estimated ultimate recovery (EUR) were made for more than 1,000 horizontal wells in the South Texas Eagle Ford shale trend and statistics were developed for EUR in the 10 primary counties where development is occurring.  The study used rate vs. time plots and  included all the producing wells in the trend which have decline data believed to be sufficient to project EUR.   Normalized decline curves were developed for each county and distributions of EUR were produced.  In addition, for a portion of the wells, correlations were made between EUR, frac size, horizontal length and the date of first production.  

The results show that for the 10 county trend, the average and median EUR per well were 206,779 barrels of oil equivalent (BOE) and 160,519 BOE, respectively.  Of the counties with more than 50 wells, the best are DeWitt (403,715 BOE) and Karnes (210,801 BOE).  Live Oak, with only 28 wells averages 248,818 BOE.  The normalized rate vs. time plots show minor hyperbolic behavior.  In fact, for all the wells in the study, the normalized oil decline was 76% and the gas 60%, with hyperbolic exponents of .25 and .40, respectively.  The wells have clearly become better since the start of horizontal drilling, but the average performance has not shown much improvement since mid-2010 even as the frac sizes became larger.  The best well performance has generally come from wells with horizontal legs in the 4,000 to 5,500 ft. range. 
The South Texas Eagle Ford shale trend is one of the most active in the US, adding approximately 100 new producing leases each month.  Although a great deal is being written about the trend, there is a lack of independent, hard data on per well reserves.  This study provides an early look at individual well ultimate recovery."

The entire paper:
http://gswindell.com/sp158207.pdf

Wednesday, January 2, 2013

EOG Keeps The Bar High

EOG has reached total depth on the Gauthier 14H-1 reaching a measured depth of 19162' (13640' TVD).  This represents the 2nd fastest TMS well drilled to date (564'/day compared to the EOG Dupuy 20H-1 at 604'/day).  This will also be the 2nd deepest completion (13640' TVD; slightly shallower than the Devon Murphy 63H-1).  The chart below compares the drilling rate of all of the TMS wells on a feet per day basis and ordered from left to right by spud date.  EOG's performance to date represents a significant development for this play.