Saturday, September 29, 2012

Thursday, September 27, 2012

Halcon Proposes Unit in Rapides Parish

It must be "unit proposal week" in the TMS.  Halcon has proposed a 960 acre unit in Rapides Parish.  Some new life is emerging in the TMS-West.

Base TMS structure; TMS units and wells

Wednesday, September 26, 2012

Goodrich Proposes Unit In St. Helena

Goodrich has proposed another TMS unit. This one is in St. Helena Parish at Joseph Branch Field (1040 acres)

EOG - New Units

EOG has proposed two new 960 acre units in Avoyelles Parish.  One is an offset to the Dupuy Land Co. #1 at Bayou Twisty Field.  The 2nd is at Vick Field and is 600-700' updip from Bayou Twisty Field.

Tuesday, September 25, 2012

Goodrich Looks To The East

Goodrich Petroleum has applied for a unit in Washington Parish, LA.  The unit falls within a large block that they've assembled.  This unit is the most eastern location/unit to date and falls outside of my 75' resistivity isopach contour.  From log analysis, I calculate 60-70' of pay in this area which is thin compared to thicker pays to the west (max 151').  This early in the game, I find this to be an interesting choice from Goodrich's sixteen blocks that are scattered across the play.  I agree with their approach to lease across the play to balance risk in a play that has yet to be derisked, but this wouldn't have been one of my early choices.  This location will provide a very interesting "data point" for the east side of the play.  Upcoming results from the Devon Thomas 38H-1 will provide more information.

Devon Goes Long

Many have been frustrated with Devon's short lateral lengths and timid frac jobs.  It sometimes feels like sitting in Tiger Stadium watching Coach Miles call his favorite two yard pass play.  The newly permitted Beech Grove 94H-1 is permitted for an 8006' lateral length.  The TMS in this area exhibits excellent log character with approximately 120' of pay.  With a long lateral and a large proppant volume, we should see results much improved from than the Beech Grove 98H-1.  The 98H-1 experienced a lot of hole issues while drilling.  It will be interesting to see if these have been resolved during the drilling of this wellbore.  In addition, Devon has stated that they've fine tuned their "target zone" in the shale.  I believe that this will be Devon's "breakout" well in this play.

Monday, September 24, 2012

Imperial Capital Conference Presentation

I've added my presentation from the Imperial Capital Conference:

Devon Thomas 38H-1 IP Prediction

Trucks are hauling oil off of the Thomas 38H-1 location, but an initial potential has not been announced.  Below are a few charts that can be used to make an IP prediction. Based on the information below, I would expect the well to IP in the 350-500 boepd range.  Devon is using more proppant per stage than in the past, so it could be higher.  I would expect the well to have little gas.  424 boepd is my prediction for an IP30.

Monday, September 17, 2012

Imperial Capital 6th Annual Global Opportunities Conference

For those attending the conference, the TMS session will be Thursday, September 20, at 2:30 p.m. at the Waldorf Astoria Hotel.

Conference website:

Friday, September 14, 2012

TMS - Decline Rates

Updated production for July has been posted on the Mississippi Oil & Gas Board site.

The chart below plots the average daily production rate (boepd) from monthly production totals.  The ranges are diverse due to the range in lateral lengths and subsequent frac jobs.

The chart below presents the oil production as a percent decline on a monthly basis.  The Encana Board of Education #1H has produced the longest. This well was originally drilled by Encore and was re-entered and completed by Encana.  I don't consider it part of this recent "era" of wells, but it does provide twelve months of production.  It exhibits nice stabilization in production rate from months four to twelve.  The other wells also exhibit a sharp decrease in decline rate in month four.  I find this very encouraging.  The faster the curve "flattens", the larger the estimated ultimate recovery (EUR).

The chart below presents the percent decline in the average daily oil rate from the peak month of production.  While the Encana BOE #1H has a 87% decline off of the peak rate, I consider this well the worst case scenario due to the history of the wellbore.  Only 1,000,000# of proppant was pumped during the frac job.  Over the next few months, the Weyerhaeuser 73H-1 and Horseshoe Hill 10H-1 will show us a lot.  The Beechgrove 68H-1 has been erratic due to mechanical issues.  The typical 12 month decline rate for the Eagle Ford is 73% and the Haynesville is 85%.  The Weyerhaeuser 73H-1 and the BOE #1H are both on artificial lift (rod pump).


Wednesday, September 12, 2012

Imperial Capital Global Opportunities Conference

I've accepted an invitation to present on the Tuscaloosa Marine Shale play at the Imperial Capital Global Opportunities Conference in New York City next week.  I will be sharing a panel with Robert Turnham, President of Goodrich Petroleum.  The TMS session will be Wednesday, September 19, at 4 p.m. in the Metropolitan Suite of the Waldorf Astoria Hotel.

Conference website:

Thursday, September 6, 2012

Barclays CEO Energy/Power Conference

** NOTE: this post has been updated with Devon Q&A.

All of the TMS players presented today at the Barclays CEO Energy/Power Conference in New York City.  Here's a summary of notes from the presentations.  All of the presentation slides are on the company websites.

355,000 net acres; 9.4 billion barrels in place
“20 MMBOE/section of petroleum initially in-place; 9500-11500’ TVD; significant oil infrastructure supporting this play; oil marketed at LA Light Sweet oil pricing, sometimes as high as $15/bbl premium over W.TX Intermediate; very encouraged with initial results; with more production history, starting to establish type curves; will release type curves in subsequent quarters; very pleased about reservoir performance, excited about it; working on Joe Jackson well; drilling 2 wells; significant progress made in establishing landing target for horizontal lateral which had reduced hole stability issues and allowed increased completion side intensities; do well when drilling vertically or horizontally; in the bend, we struggle to have good hole stability; Ash well: drilling with larger diameter casing program; once curve built, set drilling liner through curve and eliminate majority of problems that we’ve had…at least that’s the plan; additional advancements in completion design and improvements in overall well cost structure are on the horizon; seeing significant improvement in completion effectiveness; go from $18-20M well to $15M in short term to eventually $12M well cost; overall TMS reservoir doing quite nicely; still have work to do on drilling side; Dataroom is open; considerable interest so far; expect offers in the fall

“Target 5-6 plays; targeting one million acres in the company; taking position in plays with running room; seeking 50 years of oil drilling inventory”
TMS: “Starting leasing 6-7 months ago; on way to about 100,000 acres; traditional cost improvement play; zone is there; it’s thick; susceptible to modern technologies (frac jobs); well costs quite high in early phase; need $9-10M; AFE at $11M for first wells; profile in terms of measured depth of a deep EF well so shouldn’t be a problem getting there; early stages extra money spent; EUR 600-700 MBOE play; if you get 7000-8000’ laterals; depths are approaching 14000’, a lot around 10000’; going to be a bit of a challenge; moving rig in on Broadway right now then Lambright; 12 miles apart; high confidence based on old control that we’ll find what we’re looking for; approached differently; west of activity; intentionally prospect area away from thick Tuscaloosa water bearing sands, find on top of bottom of shale section; won’t have water to contend with”

“have specific buy area; hope to get to 100-150,000 acres; 1/3 of way there; $1000/acre now, up from $250 short time ago
No mention of the TMS in the slide presentation.

Same summary slide as in their most recent presentations. I did not listen to the webcast.

The TMS was only mentioned in summary slides.

Q&A: “Tuscaloosa…we’ve drilled a few wells; huge resource there, no question, awful lot of oil; been moving around our acreage position; start to understand it; some promising results, some not so promising results; what we’re seeing in better areas, seeing pretty good initial production rates; other operators seeing real good initial production rates; real question is, don’t have enough data yet; what that decline curve is going to look like. No question Lots of oil there. No question this will produce oil in significant quantities from these wells, but fairly expensive wells, they’re deep; $12M or so; all depends on the what decline curve looks like as we get more data; if decline curve real steep, you’ll probably produce 250,000 barrels, that’s nice but it’s not going to drive the economics. If you have a more hyperbolic curve, it might be more in the 400,000-500,000 bbl recoverable range which will really drive those economics;  the jury is out on that part of it; it’s in the early days; only been 20 wells drilled in area that is enormous in size; worthwhile for us to take some money continue to pursue that; it’s part of our joint venture, so for us, fortunately we have a partner that is picking up a good piece of that early exploration capital because the prize is huge if it works, but it’s early.”

Wednesday, September 5, 2012

Devon Murphy 63H-1: Post Analysis Revision

On SONRIS today I noticed that the number of stages for the Devon Murphy 63H-1 was 16 as originally thought.  I present below revised charts.

The chart below reveals that Devon is still more conservative on their proppant volume than Encana.

The chart below reveals that the Devon 63H-1 plots exactly on the "best fit" trend line.

From an IP perspective, the chart below reveals that the Devon 63H-1 plots within  the expected range based on the prior wells.

The chart below indicates that the Devon Murphy 63H-1 actually performed better than expected.  This trend line would project a 350 boepd IP.

Based on the chart below, the expected IP for a 16 stage frac based on past well would be sub-300 boepd.  The increased proppant is the reason that the Devon Murphy 63H-1 outperformed Devon's predecessor wells.

Overall, these charts indicate that while the current database is small, some predictions can be made regarding initial potentials.  They also reveal that "more is better" from a frac standpoint, but economics have to be considered.  What increased return is obtained with the longer laterals and larger proppant volumes?

TMS Drilling Rates

There still remains two boxes to check in the Tuscaloosa Marine Shale play.  They are drilling/completion costs and decline rate.  The decline rate will become apparent over the next year as this first set of wells reveals the production decline.   The chart below presents the drilling rates from the TMS wells in chronological order.  The trend illustrates slight improvement.  Encana's Anderson 17H-1 well still stands out as the "model" well for drill time.  I anxiously await EOG to start drilling their horizontals.

Source: SONRIS, MSOGB, personal communication

Source: SONRIS, MSOGB, personal communication

Tuesday, September 4, 2012

Encana Spuds the Ash 31H-1

Encana Ash 31H-1 (Photo by J.K.B. White)
Encana spud the Ash 31H-1 last night.  The well has a planned TD of 19150' with a lateral close to 7000'.