Thursday, December 11, 2014

New Wells Results - Calibration With Geologic Attributes

Two new well results were announced yesterday:
-Goodrich Verberne 5H-1: 1375 boepd
-Sanchez St. Davis #1: 1143 boepd

The chart below incorporates these two new results.  The two wells plot in the "best performers" range as expected based on their geologic attributes.

This display compares the initial potential (boepd) on a 1000' basis (y-axis) compared to the thickness of Passey DlogR>0.9 (x-axis).  The third variable, mean sonic, is presented as the size of the circle for each well.  The wells are filtered by additional variables including lateral length and proppant per stage.  At 54 completions, the "formula for success" is currently: 
-Lateral length > 4400'
-Passey pay > 100'
-Mean Sonic > 82.5 (higher sonic appears to align with the presence of natural fractures and possibly higher porosity)
-Proppant per stage: 400,000-650,000 lbs (Encana Sabine 12H wells recently used ~800,000 lbs; the production decline profile will be one to watch in the coming months)
-Landing zone: lower TMS (recent Sanchez St. Davis landed high; the production decline profile will be one to watch in the coming months)

Note that the last 10-12 wells that meet these criteria have had excellent results.  
Repeatability has been confirmed.

Thursday, November 20, 2014

TMS Consortium - GCAGS Paper

Our first research thesis from the Tuscaloosa Marine Shale Graduate Research Consortium (TMSGRC), has been released as a GCAGS paper (LSU: Hunter Berch).

Our second research thesis will be presented to the thesis committee tomorrow at the University of Louisiana Lafayette.

Wednesday, November 5, 2014

Tuesday, November 4, 2014

TMS Energy Summit

I've placed my presentation online from the LOUISIANA ENERGY SUMMIT that was held on LSU's campus two weeks ago. The analytics might be useful today for comparison with the announcement of two new well results.

Don't forget to tune into Goodrich's earnings call at 10 a.m. CDT today

Friday, October 10, 2014

Halcon Permits Well In Tangipahoa Parish, LA

Halcon has permitted their first well on their Tangipahoa acreage block. The TMS RA SUB;FRANKLIN PST PROP H-1 is permitted for a measured depth of 17978 and true vertical depth of 11667. This location is near Goodrich's Blades 33H-1 and two active rigs.  A Comstock rig will begin drilling soon just west of here.  On a per 1000' lateral basis, the Blades 33H-1 is one of the best wells in the play to date.


Friday, October 3, 2014

Encana Raises The Bar

The MSOGB has an initial test reported for the Encana Lyons 35H-2.  On a per 1000' lateral basis, this is a record setter. The Encana Anderson 17H-2 had a similar test, but didn't have significant follow on production.  The 35H-2 only had a lateral length of 5200' and initially tested 1337 bo x 1075 mcfg (1516 boepd).  This almost surpasses the best IP of any length. The chart below depicts the initial tests on a 1000' lateral basis.  Note both the consistency from recent tests along with the cluster of recent activity.  The wells are presented chronologically based on spud date.


Monday, September 29, 2014

Goodrich Announces Well Results

It's nice to have some new results to talk about!  Goodrich released this update this morning:

HOUSTON, Sept. 29, 2014 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE: GDP) today announced a Tuscaloosa Marine Shale ("TMS") operational update. The Company's Bates 25-24H-1 (98% WI) well in Amite County, Mississippi, which was completed with an approximate 4,850 foot lateral and was fracked with 19 stages, achieved a peak 24-hour average production rate of 1,000 barrels of oil equivalent ("BOE") per day, comprised of 938 barrels of oil and 373 Mcf of gas on a 17/64 inch choke. The Company's CMR/Foster Creek 31-22H-1 (90% WI) well in Wilkinson County, Mississippi, which was completed with an approximate 6,700 foot lateral and was fracked with 24 stages, is in the early stage of flowback, with a current peak 24-hour average production rate to date of approximately 1,140 barrels of oil equivalent ("BOE") per day, comprised of 1,070 barrels of oil and 420 Mcf of gas on a 13/64 inch choke. The Company will provide an update on the well on its third quarter earnings press release. The Company is currently conducting completion operations on its CMR/Foster Creek24-13H-1 (97% WI) well in Wilkinson County, Mississippi, which has an approximate 6,600 foot lateral with 24 frac stages and should begin flowback within a week. The Company has also drilled and is in completion phase on its Spears 31-6H-1 (77% WI) well in Amite County, Mississippi, which has an approximate 7,600 foot lateral, and its Verberne 5H-1 (66% WI) well in Tangipahoa Parish, Louisiana, which has an approximate 6,800 foot lateral and reached total depth within 29 days. The Company currently has three rigs running in the play and is conducting drilling operations on its Williams 46H-1 (61% WI) well in Tangipahoa Parish, Louisiana, itsCMR/Foster Creek 8H-1 and 8H-2 (79% WI) wells in Wilkinson County, Mississippi, and expects to commence operations soon on its T. Lewis 7-38H-1 (estimated 90.5% WI) well in Amite County, Mississippi. The Company has in excess of 300,000 net acres in the play. A copy of the latest corporate presentation is available on the Company's website at

Here are three charts comparing initial potential results.  The selected well group have similar frac designs, lateral lengths > 5000', and landed in the lower portion of the TMS. Both of the new wells fall right on the averages. We're starting to see consistency in the well results which is very positive.




Thursday, September 4, 2014

Wednesday, September 3, 2014

Tuesday, September 2, 2014

Goodrich Operational Update

Goodrich Petroleum Announces Tuscaloosa Marine Shale ("TMS") Operational Update 
 HOUSTON, Sept. 2, 2014 /PRNewswire/ --
Goodrich Petroleum Corporation (NYSE: GDP) today announced the completion of its Denkmann 33-28H-2 (75% WI) well in Amite County, Mississippi. The well, which was drilled with an approximate 6,000 foot lateral and was fracked with 22 stages, has achieved a peak 24-hour average production rate to date of approximately 1,250 barrels of oil equivalent ("BOE") per day, comprised of 1,200 barrels of oil and 300 Mcf of gas on a 16/64 inch choke. The Company has also commenced flowback on its Bates 25-24H-1 (98% WI) well in Amite County, Mississippi, an approximate 5,000 foot lateral with 19 frac stages, and is currently fracking its CMR/Foster Creek 31-22H-1 (90% WI) well in Wilkinson County, Mississippi, which has an approximate 6,700 foot lateral with 24 planned frac stages. The Company has also drilled and is in completion phase on its CMR/Foster Creek 24-13H-1 (97% WI) well in Wilkinson County, Mississippi, which has an approximate 6,600 foot lateral, and its Spears 31-6H-1 (77% WI) well in Amite County, Mississippi, which has an approximate 7,600 foot lateral. The Company currently has three rigs running in the play and is conducting drilling operations on its Verberne 5H-1 (66% WI) and Williams 46H-1 (61% WI) wells offsetting its Blades 33H-1 (67% WI) well in Tangipahoa Parish, Louisiana, and its CMR/Foster Creek 8H-1 (79% WI) well in Wilkinson County, Mississippi, which is planned for a two well pad offsetting the Company's Crosby 12H-1 (50% WI) well. The Company has in excess of 300,000 net acres in the play.

Tuesday, August 19, 2014


Stop by our booth at NAPE (Booth #3514)

  • TMS: 
    • 118,000 net acres (6 packages: 2600-50000 acres)
    • EUR: 500-850 MBOE
    • IP Range: 700-1550 boepd
  • Saratoga Chalk
    • Re-develop 40 MMBO field with horizontals
    • 3000' TVD
    • 36,000 net acres
    • DHC/CC: $1.4M
    • EUR: 80-130 MBO
  • Bossier Sands
    • 3100 acres
    • HBP: 916 mcfgd (Cotton Valley)
    • IP range: 14-32 mmcfgd

Monday, August 11, 2014

EOG Re-Ignites the TMS-West

Field reports from Central Louisiana indicate that EOG has moved in a H&P rig and has spud the Indigo 25H #1 TMS well (API 1711520230) located in Section 25, T3N-R7W in Northeast Vernon Parish, LA. According to a filed permit with the state, the well will have a measured total depth of 17,318’ which may imply a 5,000’ to 6,000’ lateral in the objective TMS section. By virtue of the well name, it appears that Indigo Minerals is a partner in the well. Indigo has been active in the West side of the TMS play since 2010 acquiring leasehold along with its large fee mineral position, and drilled one horizontal TMS well in 2011 that was junked due to fish stuck in the lateral. From previous land maps presented in the area, it appears EOG also has a significant acreage position in the Vernon Parish, LA area. This will mark EOG’s 5th TMS well in the play with the other 4 TMS producers located back to the East in Avoyelles Parish, LA. This new Indigo Minerals 25H #1 well will be very significant for "proving up" the TMS West. Good luck EOG and Indigo!

Friday, August 8, 2014

Goodrich Petroleum Earnings Call - Q2-2014

Goodrich did an excellent job yesterday providing an update on their operations in the play. As in prior calls, they provided great detail on their current interpretation of the play.  I don't disagree with any statements that were made regarding the geological and reservoir aspects of the play. 

My recent post regarding "geology matters" was timely.  The significance of porosity and natural fractures is starting to reveal itself.  As mentioned during many presentations, resistivity is not the only variable to evaluate.  I posted a white paper on resistivity a couple of years ago. It might provide some interesting insight. Acquiring leases based on a resistivity isopach map and a mudlog show might prove to be problematic.  The porosity provides storage and the natural fractures provide a mechanism for rapid production of the oil.  It's very likely that the "less fractured" TMS will require a different frac design to achieve economic results.  The mega-frac used on some prior wells with proppant ranging from 700-1000k lbs per stage might be worth trying on this different rock type.  Ultimately, as stated yesterday by Goodrich, the less naturally fractured rock type might present flatter declines and very attractive EUR's and IRR's.  With only 42 completions to date in the play, many more details will be revealed in the future. Keep in mind, that the Eagle Ford play was at 42 completions in 2009. Look what has happened there since then.

I'm currently working on a new white paper addressing this "rock type" theory.  Recent results indicate that there potentially are two "rock types" exhibiting different properties. Both will likely yield attractive economics.  Frac designs will be different for each. The reservoir attributes change gradually presenting a spectrum across the two rock types.  Below is a teaser of details to come in the next few days.  The current theory that depth and porosity/fractures are related is wrong.  With few TMS horizontals drilled to date, it's easy to "connect the dots" based on the current well dataset. Don't forget that there are hundreds of wells that drilled through the TMS over the past thirty years. Those well logs provide a robust dataset to map the reservoir attributes of the TMS.  It's my belief that to succeed across the TMS, you have to understand the distribution of the "silty facies" which impacts porosity and natural fractures.  

The data below illustrates that "Crosby-like" log parameters exist across all depths and below 16000' TVD in some areas. Understanding the spatial distribution of the silty facies will be key.

Data: 133 vertical wells; LAS files

Here are my takeaways from the call (my comments in CAPS):
-44 completions; 12 drilling/completing
-delineation wells: SLC, B-Grove, Nunnery
-rubble zone: drill through at steeper angle has become the best practice next series
-Current Drilling: CMR 31-22, CMR 24-13, Spears 31-6, Denkmann; in derisked fairway; developmental wells; Bates pushing northern edge; plan to accelerate development
-depth limit for costs? depth not huge driver; 1000-2000' vertical is not big issue, few days in drilling time; BHP takes more horsepower and pump pressure to get frac off; not tremendous higher expense; no portion of the play is going to be materially more or less expensive; get wells down vertically quickly; deeper requires more horsepower; pad drilling will be the key to costs
-Crosby to Blades: derisked fairway 
-Bates: last delineation; sufficiently thick, thicker than Nunnery; 
-Bramlette well in early 2015 
-Eastern block (Blades area): 3 permits in the queue; 3 spud in 2014 near Blades; Blades good 60-90 day production; two rigs simultaneous at one point in the area

-showing variability: rock properties important; better perm increased fracs = better performance 
-east-west: 10500-14000' tvd - most prolific; cover 90% of GDP acreage
-will see variability; variability in first 45 days due to fractures
-natural fractures vs depth: B-Grove and SLC not as much natural fracturing based on drilling
-1200-1500 initial rates are probably due to more natural fractures; -geologic data presents no difference in rock properties including SLC and B-Grove
-depth is an open question as this point 
-any way to map natural fractures? difficult; have been working with Schlumberger to run logs that analyze fractures; have been doing some work regarding fracture identification; 
-3D seismic in planning, not sure if it will have resolution to see fractures; frequent in occurrence (1 every 1.5-2';see on schlumberger log); vertical in nature; contained within TMS section); will be trial and error; possible build frac model with logs through time 
-Isopach map: it is important; where the thickness cutoff is; Nunnery thinner, IP less, possibly due to thickness; substantially thick in SLC and BG, plenty of thickness, comes back to matrix por/perm coupled with natural fractures; trial and error; drawing bullseye considered more "core in nature"; overlay porosity with resistivity (Passey)
-thickness has bearing on EUR, predicated on matrix performance; high IPs driven by natural fractures 
-GOR surprise that not more gassy? not seen anything yet suggesting gas phase to play; Lane: conventional core RO slightly higher thermal maturity; see more gas down there, way up in black crude oil; entire play way up in % of black crude oil

-type curves holding
-type curves yield economic returns at current prices 
-conclude that better wells have more fractures; wells with IP < 700 boepd exhibit flatter declines; due to less fractures but similar matrix porosity 
-correlation with proppant per lateral foot and results 
-Beech Grove curve crossed over the type curve after 30 days
 -nice evidence of benefit if you have lower choke early on; reservoir wants to surge, push fluids through formation at a fast pace; see benefits early on for conservative choke management; -SLC: 0.7 psi/ft; 10000 lbs of BHP, more prudent to be conservative, adjust choke over time; 
-Nunnery: run tubing and put on jet pump; nice response;

-550k/stage average now making best wells with right spacing and hybrid job
-nice correlation between proppant/ft and projected EUR
-too much fluid per proppant has worse results; hybrid with gels after fluid introduction 
-250-270' frac intervals; blades: 250' spacing 

initiate soft process for partners; early phase discussions 3 rigs running; accelearate with JV or raise more capital delineation phase over: drill in proven fairway;
-JV price: min $5000/ac for all, higher for core

Monday, August 4, 2014

Play Activity

The project has 20 wells in play either drilling, completing, or flowing back. I would expect to get three official well results on Thursday during Goodrich's earnings call.

Friday, August 1, 2014

Halcon Earnings Call - TMS Notes

Halcon had their earnings call yesterday. Here are my takeaways:
-DRILLING: 2 rigs in TMS; drilling days reducing 15-20%; all operators expected to increase rig counts; 50 wells drilled so far; last 10 mostly good; Blackstone 4H-2: 22 stages all frac-ed well; in clean out process and we'll start flow back here; get the cost down within 2 years from where they are down to that under $12 million range
-COMPLETION: tight range of frac job volumes of proppant and water being used; everyone's following fairly similar programs and you're going to see more comparable results across the industry going forward; it's a tough nut to crack down here, but we expect to significantly reduced cost over a couple of years
-PRODUCTION: performing to expectations; type curve remain exactly where they've been
-RESERVOIR: just record 200 feet of continuous conventional core in the Smith well; about 10 cores taken in last 3 years; got fantastic data in the Smith well, in the core, and all the modern suite of logs we ran in. That well maps out as being having one of the highest original oil in place of any well in the whole play
-FACILITIES: expect to build first compression nat-gas facility next year; building a 3-phase gathering system in centralized gathering facilities; plan to build a crude oil handling facility at the Port of Natchez in Mississippi
-LAND/LEASE:  acreage is pretty tight in the TMS, and we have so much that it would be like gluttony to just to think we have to have more.
-FINANCIAL: signed agreement with Apollo Global management, which may invest up to $400 million in our wholly-owned subsidiary, HK TMS.

Halcon Earnings Call Transcript - TMS Highlights
We have -- company-wide we've got 14 operated wells being completed or waiting on completion and probably 3x as many non-op wells as that. We're running 8 rigs right now, 3 in the Williston, 3 in East Texas, El Halcón and 2 in the TMS.
Tuscaloosa Marine Shale, of course, is on everybody's radar screen these days. We're running 2 rigs in the play. And with continued progress and success, our rig count could easily double early next year. Economics are expected to improve over time as they have in every other resource play in the United States. We believe the quick win -- we believe we can reduce the number of drilling days by 15% to 20% on average throughout the remainder of this year.
We understand that other operators expect to increase rig counts and all this leads to a lot more information in the field. If you think about the play, I guess there's been about 50 wells drilled so far. The first large number of those were not so good. A few good ones in there. The last 10 wells drilled in the play has been mostly good wells, so it's a traditional learning curve situation that's going on there and we're pretty happy to be there.
We are working interest partner in several wells that are performing to expectations and give us added confidence that the industry as a whole has continued and will continue to make progress in this play. Specifically, the average IP rate of the producing non-op wells that are near us, that we have an interest in, has been about 1,100 barrels of oil a day, not including gas. Include gas as over 1,300 barrel of oil equivalent. So it's an early stage play and, as I said, we're very happy to be there.Our field services unit continues to work on several initiatives they have the potential to improve, realize prices and margins in all of our plays. Our first compression natural gas facility is expected to be in service by end of this quarter at El Halcón. We'll use CNG to displace diesel fuel. This isn't only green but is also could result in a nearly 50% savings on fuel cost in frac-ed jobs and with drilling rigs.
We expect to build similar facilities and service operations at the Williston Basin and in the TMS next year.
HFS continues to provide low pressure gathering services in El Halcón and plans to support the TMS by building a 3-phase gathering system in centralized gathering facilities located throughout the play where we have clusters of wells.
Centralized aggregation points are expected to reduce the overall cost of facilities and allow for more efficient transportation of both crude oil natural gas and produced water.
Our central facilities will be located with access to one or more gas pipelines as well. The system design and layout are both substantially complete, and we plan to begin permitting for a processing plant at our facilities during this quarter. We also continue to develop a crude oil handling facility at the Port of Natchez in Mississippi. This is in the planning stage. That will be a facility capable of handling truck and pipe offloading from the TMS. And to market the crude via barge on Mississippi River or by rail. We're working on that as we speak as well.
As mentioned, we have sold certain non-core assets in East Texas for about $450 million during the second quarter, which had an effect on our borrowing base of a reduction of about $100 million to our current base of $700 million. And, as previously disclosed, we also announced the signing and the closing of a agreement with Apollo Global management, which may invest up to $400 million in our wholly-owned subsidiary, HK TMS.
In about mid-June of this year, Apollo did fund the first phase and contributed $150 million in cash consideration for 150,000 of HK TMS preferred shares, and they can acquire an additional 250,000 preferred shares of HK TMS on the same terms.
Lease acquisition, seismic, infrastructure and other came in at about $224 million for the quarter. As part of our agreement with Apollo, we accelerated about $127 million payment to Encana on the acquisition of certain properties perspective for the TMS. We had originally planned on deferring these payments throughout 2014 and then 2015, but that was accelerated. We expect lease acquisition, seismic and infrastructure expenditures to be significantly lower for the remainder of the year.
Jason A. Wangler - Wunderlich Securities Inc., Research Division
I'm curious on the Black Stone well. You just kind of give us a little bit of indication of the well was pumped all through the frac stages, but then there was some issues. Do you have an idea yet of how -- will the frac stages still be able to go off? Or will that shortened kind of the effective laterals? Or just kind of give us some color on that?
Floyd C. Wilson - Chairman and Chief Executive Officer
We don't know yet. All the -- I think there are 22 stages, they're all frac-ed well. We are just in that clean out process and we'll start flow back here. We're just not quite there.
Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division
So, Floyd, just wondering what you've seen so far in these 3 TMS wells. Obviously, just the one you have down and, obviously, you've got a lot going on right now. As your thoughts changed as far as the way you're going to obviously drill and complete these? A lot of these guys talking about, above or below the rubble zone? Just wonder what you've seen -- 2 questions around this. Have your thoughts changed on how you want to sort of tackle these? And number two, just -- you had early EUR estimates sort of on your type curve -- is that changed either?
Floyd C. Wilson - Chairman and Chief Executive Officer
It's pretty interesting what's going on there, and Charles can add to this if there's something to be added. But you've got 3 operators running multiple rigs there now. All of those operators are targeting about the same area, if there aren't any other conditions that direct you to go somewhere else in terms of the placement of lateral. And the operators are actually a pretty tight range of frac job volumes of proppant and water. There are some differences, but -- so what you've got is currently everyone's following fairly similar programs and you're going to see more comparable results across the industry going forward than you've been able to see in the past between targeting and small fracs and large fracs and slickwater back in the day. It's just hasn't been as consistent as it is right now. Our thoughts on the type curve remain exactly where they've been. Our thoughts on cost remained at -- it's a tough nut to crack down here, but we expect to significantly reduced cost over a couple of years. And we haven't changed our thoughts along those lines at all. Anything else, Charles?
Charles E. Cusack - Chief Operating Officer and Executive Vice President
No, that's pretty well covered it.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
And then as more -- with almost 20 rigs in the play, it seems like that play is just being delineated much greater. I know you've concentrated your position in a -- that 100,000 acres and where it's located. Any opportunities to expand in that area and/or even in the TMS, as some of that play has moved a little bit to the Southeast into especially Tangipahoa?
Floyd C. Wilson - Chairman and Chief Executive Officer
Well, again, the acreage is pretty tight in the TMS, and we have so much that it would be like gluttony to just to think we have to have more. And at El Halcón, we were probably a little too conservative when we drew our map the first time. And I mean, we outlined a bull's-eye there. That has been 100% accurate, but our bull's-eye could have been a little bit larger. Some of the smart Companies who come in there and bought land all around the edges of where our bull's-eye was and they're doing quite well. So it's very tight there too. So I -- we're always looking in any of our areas, but we're not seeing any large deals in the Williston or the TMS, or in El Halcón that are in the area that we'd want to be and at this time.
Robert Bellinski - Morningstar Inc., Research Division
Okay. And then in the TMS, how many core samples do you expect to recover? And are those just planned for Wilkinson County at this point? Or are you looking to pull some samples across your position? And then as a follow-up, do you guys have any preliminary thoughts that you can share at this point?
Floyd C. Wilson - Chairman and Chief Executive Officer
We just record 200 feet of continuous conventional core in the Smith well. And that was an area of the play that did not previously have conventional core. But between us and the other operators, there's about 10 cores now. Few other operators would be getting a couple of others that we'll have access to, so that we don't plan on taking any others near-term right now. But we got fantastic data in the Smith well, in the core, and all the modern suite of logs we ran in. That well maps out as being having one of the highest original oil in place of any well in the whole field .
Dan McSpirit - BMO Capital Markets Canada
A question on the TMS. If we look out 12 months from now, on the play, what should we expect to see in terms of drilling complete cost, production profiles and maybe ultimate recoveries? That's a, I guess, it's a long way of asking about expectations on fuel level of returns. And how they're expected to change? And what is the internal hurdle at the company that is the internal rate at the company that needs to be met?
Floyd C. Wilson - Chairman and Chief Executive Officer
Well, taking this in reverse order, the -- our internal hurdle is our published type curve. And the cost side of that is to get the cost down within 2 years from where they are down to that under $12 million range, somewhere within that range. We're very comfortable. We're going to make it on the production side, and that the industry is going to make it by the way. The costs -- it's a tough deal down there, and it's a hard area to drill in and hard area to complete wells in. But I think 1 year out, you would expect to see less trouble from all the operators. You'd expect to see more consistency in terms of completion, design and targeting because we're all conversely -- we've got a really awesome information sharing agreement with the other large operators in the play, and we're very open and supportive with all of them. They're great, great people to be in business with. So I think you're going to see a steady inching down of cost. And if it follows the pattern of these other plays, Dan. You have to understand that the type curves in other basin started out at where there's 300,000 barrels or 2 or 3 Bs or something, and I didn't find the best wells early. They didn't find the best geologic spot early, nor did they find the best completion technology early. So I'd be surprised if there's not a few million barrel wells down in here within the next year, but I don't know that.
Jeffrey W. Robertson - Barclays Capital, Research Division
Floyd, just a question on Halcón Field Services. Can you talk in a little bit more detail about the port -- oil handling facility at Natchez and how you -- what kind of capital you might have for that in 2015? And is there an initial number of barrels that you plan to be able to handle in that project? And then lastly, would you, at some point, start to look for a partner to come in and help that project like you all did back in the Haynesville?
Floyd C. Wilson - Chairman and Chief Executive Officer
The capital associated with this best project, if it's fully -- if it's gets fully built, as what we examine -- as what we think, it's not that much. So for right now, the idea is to get your crude oil away from a local market, which would be a truck market controlled by refiners and perhaps local buyers, and get it floating on the Mississippi river or get it to a rail to where it can be used for others. Most of refining capacity in the United States is available to that area. It can be used for blending or whatever. So for now, we're doing all the planning. We've acquired some land and, which is very small amounts of money. We haven't really published the numbers on that, but it wouldn't happen until later in '15 in terms of the spend, but it could be $15 million or $20 million initially. And it's not a ton of money and -- but what you could find yourself is gaining dollars per barrel in terms of price discovery as opposed to just spending money. And so I -- we're really high on it. What we've done in the past, is make sure that if an idea is going to -- is working that we built far enough out that our own plans are going to be served, if you bring someone in that maybe has a different capital plan in sales or something. So it's so premature to talk about bringing anyone in and anything like that, but we would intend to get storage capacity up pretty high in the hundreds of thousands of barrels. We would think that it would be a good outlook for others, but it's early to get into that.
Jeffrey W. Robertson - Barclays Capital, Research Division
Then one other question, Floyd. Have you all learned anything from your activity in the TMS that makes you thing differently about the acreage you have over to the West?
Floyd C. Wilson - Chairman and Chief Executive Officer
No, we just have so much acreage in Wilkinson County, just South of Wilkinson County. We just don't have to think about that acreage to the West for some longtime. What we've learned is that we had a really good show there, and we lost a well before we were able to get the full things drilled, but we had a really good show. It's a different part of the basin. It's a little hotter. It's a little gassier. A lot of crude oil over there, but we just don't have to -- we're just not going over there right now. I mean, it's pretty interesting, but it's just not on our radar screen this year or next for sure.
Andrew Coleman - Raymond James & Associates, Inc., Research Division
Okay. And then, I guess, if we look at the oil mix, I mean, at this point, the differentials are primarily, I guess, skewed by Bakken barrels at this point. I think that was your previous discussion, one of the questions, a couple of seconds ago. But as you bring on the extra TMS barrels in that, do you have a view as to where differentials may trend to, aside from tighter?
Floyd C. Wilson - Chairman and Chief Executive Officer
Well, we're going to expect that -- if you just think of this in a general sense. Since it's closer to refineries, both El Halcón and the TMS and the Williston Basin, it's always going to be a price advantage just because of the simple cost to transportation. In terms of Louisiana Light brand, heavy crude from the Canada or -- and all this stuff, I don't know about all that is, it's a pretty complex thing that's going on. We just think that, that area is going to be -- have a small advantage over other areas just because of its location.


Monday, July 14, 2014

Beech Grove 94H-1 Results

Due to the volatility in trading, I delayed making any comments regarding Goodrich's Beech Grove 94H-1 well results.  A week ago, Goodrich released an IP of 740 boepd.  My prior post laid the foundation for a discussion on the geological parameters and their impact on production performance.  I do not know any of the details on the drill and completion of the Beech Grove 94H-1.  The press release indicates that the lateral length was 6000' and the lateral landed in the lower part of the TMS.  Assuming that everything went well and the completion recipe was consistent with the last six wells, I would have expected ~1000 boepd for an initial test.  If that were the case, then one must analyze the location and determine what geological parameter(s) was different (25% off expectation).  Despite the fact that Devon released photographs of natural fractures in conventional core from 15500', the financial gurus are trying to pin the Beech Grove results on the deeper depth stating that fractures don't exist in the deeper parts of the play. I believe that Goodrich's SLC 81H-1 will prove that to be false.

At the Infocast TMS Summit last month, I presented some geological interpretations indicating "axes" that exist across this trend in not only the TMS, but also the Tuscaloosa sands below and above, and the Austin Chalk.  These axes represent both dip-trending sediment source fairways along with strike-trending "current reworked" fairways.  Lithology, facies, porosity, permeability, and natural fractures might have slight (~10-25%) variability in some areas due to the proximity to the axis. These won't present huge variability, but might be a factor of 100 MBOE per well in some cases.  The Beech Grove lies south of a dip-trending axis in an area that exhibits "thinner" pay.  Just north is the Devon Richland Plantation 74H-1 that had respectable results for a well that only used 92000 pounds of proppant per stage.

I look forward to the Goodrich SLC 81H-1 results. As mentioned prior, this well is thicker than the Beech Grove.  Offset wells have calculated pay thicknesses of: 114', 122', 128', and 174'.  It is located at a nice intersection of "axes" which should present some nice natural fractures.  This will be the first real test of the Washita Basin. I believe that we'll see some exciting results.

Monday, June 23, 2014

Geology Matters

I was entertained by an infamous Baton Rouge landman in July, 2011 when he told me, "It's a shale play. Geology doesn't matter!!".
Well maybe the time has come for the TMS geology to start to reveal itself.  

In the past, I've presented a list of "model wells" that meet these three criteria: 1) per stage proppant level of 425-600k 2) a lateral length of at least 5000' and 3) a landing zone in the bottom 70' of the TMS.  If all three of these criteria are met, a good result has occurred.  

Last week a result of 815 boepd was released for the Goodrich Nunnery 12H-1.  The "financial quants" appeared to be disappointed. With a net pay of 75', this result is not only expected, but good for the pay thickness.  At a TVD-SS of -10800', this well with improved initial rate and lower costs will present positive economics in the months ahead.  The main "takeaway" from the result is that every location is not "geologically" equal.  Thickness, depth, pressure, natural fractures, GOR, TOC, porosity, and permeability will all come into play.  I have presented the Passey Log Method many times in my presentations.  It is my conclusion that this analysis method works very well in this play and presents consistent trends.  Isopaching D-Log-R will define very clear trends in pay thickness.  The GDP Lewis 30-19H-1 has 110' of net pay and had an initial potential of 1450 boepd.  

Most importantly, initial potentials are not very good for assessing future well results.  Yes, it gives you an initial rate, but the first 30 days of production provides a much better "initial metric". Ultimately the decline curve over the first year will be most significant.

In the coming weeks, we will see another geological contrast with the GDP SLC 81H-1 and the GDP Beech Grove 94H-1.  The net pay in the Beech Grove of 95' will not likely compare in result with the SLC 81H-1 (157').  Through time, the thickness will be added as a 4th dimension to the "model wells" criteria.  The Nunnery 12H-1 is a good example of a well that met the first three criteria, but the thickness of porous, naturally fractured, organic rock makes a difference.

The chart below compares the results from five recent wells.

Monday, June 16, 2014

2nd Annual TMS Summit - Infocast

I look forward to seeing everyone at the TMS Summit this week.

TMS Masters Thesis - John E. Allen

University of Southern Mississippi Geology masters student, John Allen, has just published his TMS thesis "DETERMINING HYDROCARBON DISTRIBUTION USING RESISTIVITY, TUSCALOOSA MARINE SHALE, SOUTHWESTERN MISSISSIPPI"
Here's a link for downloading the PDF version:

Note that this research was not conducted as part of the Tuscaloosa Marine Shale Graduate Research Consortium (TMSGRC).

Tuesday, June 10, 2014

Gas Oil Ratio

Halcon's announcement of the initial potential rate for the Horseshoe Hill 11-22H-1 yesterday revealed a higher than expected GOR.  I've integrated that into an updated GOR map of the play. It's starting to take some shape and reveal possibly some "dip oriented" trends versus just a "strike" trend aligned with depth.

Monday, June 9, 2014

Halcon Provides TMS Update

Halcon made an announcement covering several aspects of their TMS project. Here's my commentary:
-Horseshoe Ill 11-22H-1:
----excellent initial potential; Using a boepd/1000' factor from the Blades well, I estimated an IP of 1930 boepd. Using a boepd/stage factor from the Blades well, I esimated an IP of 2032 boepd but that was using 32 stages. With 24 stages confirmed, that would equate to 1524 boepd.  The IP without the estimated NGL's for the Horseshoe Hill well is 1391 boepd.  This equates to a 9% error compared to the 12% error on the Lewis well estimate. These are starting to get close now that the completion "recipe" is more consistent.  Being that the stage spacing is still varying, using the boepd/1000' factor will be less accurate in the near term.
----Gas/Oil Ratio higher than expected; high GOR is good because the gas helps to lift the oil; it enhances flow rate and ultimately long term production. The Crosby 12H-1 also had a higher than expected GOR.
----long lateral of 7060' drilled quickly - major improvement
----39 days to drill spud to TD is excellent especially considering the long lateral
-Significant commitment: spud 10 to 12 operated wells in the TMS running an average of two rigs in 2014.  The Company also expects to participate in 15 to 20 non-operated TMS wells in 2014.
-Apollo funding: significant capital provider endorses the play; hard to calculate a $/Acre value on the deal; indicates long term commitment to the project
-Midstream commitments: also indicates long term commitment to the play

Press Release
June 9, 2014

Halcon Provides Tuscaloosa Marine Shale ("TMS") Operational Update and Announces TMS Development Partnership

1,548 Boe/d IP Rate on Horseshoe Hill 11-22H-1

HOUSTON, TEXASJune 9, 2014 (GLOBE NEWSWIRE) -- Halcón Resources Corporation (NYSE: HK) ("Halcón" or the "Company") today provided an operational update related to its 314,000 net acre position in the Tuscaloosa Marine Shale ("TMS").
The Horseshoe Hill 11-22H-1 (92% WI) well in Wilkinson County, Mississippi, achieved a 24-hour average initial production rate of 1,208 barrels of oil per day and 1.1 million cubic feet per day of 1,551 BTU natural gas on a 19/64 inch choke.  Based on gas composition analysis and assuming full ethane recovery, the Company estimates that the well would produce an additional 212 barrels of NGLs per day for a total 24-hour average initial production rate of 1,548 barrels of oil equivalent per day.  The well has a 7,060' effective lateral and was completed with 24 frac stages, 21 of which were effectively pumped and 3 of which were partially pumped (less proppant placed than designed).  Halcón drilled this well in 39 days (spud to TD).
The Company has drilled the Black Stone 4H-2 (87% WI) well in Wilkinson County, Mississippi, in 28 days (spud to TD) with a 5,400' lateral.  Completion operations are expected to commence this month.
Halcón recently spudded the Fassman 9H-1 (84% WI), located in Wilkinson County, Mississippi, with a second rig and is planning a 6,030' lateral for this well.
The Company has also spudded the SD Smith 1H (62% WI), located in Wilkinson County, Mississippi, and is planning a 7,660' lateral for this well. 
Halcón plans to spud 10 to 12 operated wells in the TMS running an average of two rigs in 2014.  The Company also expects to participate in 15 to 20 non-operated TMS wells in 2014.
In addition, Halcón announced the signing of a definitive agreement with credit funds and accounts managed by affiliates of Apollo Global Management, LLC (NYSE: APO) (together with its consolidated subsidiaries, "Apollo"), which will invest up to $400 million in the Company's wholly owned subsidiary, HK TMS, LLC ("HK TMS").  Upon closing, HK TMS will hold all of Halcón's acreage in Mississippi and Louisiana that is prospective for the TMS formation.  The Company holds 100% of the common shares of HK TMS and is the sole manager of HK TMS.  Apollo will contribute $150 million in cash consideration for 150,000 of HK TMS preferred shares, and under certain circumstances, may acquire up to an additional 250,000 preferred shares of HK TMS on the same terms.  Holders of the HK TMS preferred shares will receive quarterly cash dividends of 8% per annum.     
In conjunction with the issuance of the preferred shares, HK TMS agreed to assign a 4.0% overriding royalty interest ("ORRI"), subject to reduction to 2.0% under certain circumstances, in 75 net wells to be drilled and completed on its TMS acreage. The number of wells subject to the ORRI will increase to the extent that Apollo subscribes for additional preferred shares, with a maximum of 200 net wells subject to such ORRI if Apollo subscribes for the full additional 250,000 preferred shares.
Jefferies LLC acted as exclusive financial advisor to Halcón in connection with the TMS partnership with Apollo.
The Company's midstream subsidiary, Halcón Field Services, has acquired rights to develop an oil handling terminal at the Port of Natchez, a location with direct access to more than two million barrels per day of refining capacity on the Lower Mississippi River.  The Port of Natchez has existing infrastructure including loading docks, pipelines and direct access to the Canadian National railroad. 
Floyd C. Wilson, Chairman and Chief Executive Officer, commented, "We are off to a solid start in the TMS, and the capital from our partnership with Apollo will help us to accelerate activity.  The TMS is quickly evolving into a world-class oil play."

Friday, June 6, 2014

EOG Permits Well In The TMS-West

EOG has permitted a well in Vernon Parish in the TMS-West. They will be drilling the well with 50% partner, Indigo Minerals. The well should spud in July. This will be a significant test for the TMS-West. I hope that the TMS-West reignites.

EOG Resources Indigo Minerals 25H-1
Measured Depth: 17318'
True Vertical Depth: 11985'
Lateral Length: 5333'
2277' FNL & 2444' FEL OF SEC 25. PBHL: 2097' FNL & 2486' FEL OF SEC 24.

Monday, June 2, 2014

Goodrich Lewis 30-19H-1 Results

Goodrich announced excellent results for the Lewis 30-19H-1 well today. The well achieved a peak 24-hour average production rate to date of 1,450 barrels of oil equivalent ("BOE") per day, comprised of 1,387 barrels of oil and 377 Mcf of gas on a 16/64 inch choke from an approximate 6,600 foot lateral. The well landed in the Company's lower target and was completed with 26 frac stages.
Entire press release

In my last post, I provided some predictions based on two factors: boepd/1000' and boepd per stage. The estimates were 12% above the reported rate.  I've updated the charts below to include the latest well. The Lewis 30-19H-1 has an above average factor in both cases. 
Congrats to Goodrich for another outstanding TMS well.

Wednesday, May 28, 2014

Initial Potential - Metrics and Predictions

After thirty four completions in the TMS, I believe that six wells serve as the "model wells" based on the fact that they meet these three criteria:
1) Lateral > 5000'
2) Landing zone in the bottom 70' of the TMS
3) Proppant per stage volume between 475,000-600,000

The first two charts below are in chronological order from left to right. The charts illustrate a continuous improvement in initial potentials both on a "per 1000' of lateral basis" and on a "per stage" basis.  That is very encouraging. The third and fourth charts indicate that more proppant is yielding better results, but prior wells have indicated that volumes greater than 700,000 pounds per stage is not advised. The "proppant per stage" presents a very tight correlation with the "IP per 1000 foot". This builds confidence for predicting future results. 

With that said, I've used both "factors" to present some predictions on two upcoming tests.  I'll add more once I get confirmed lateral lengths.  The bottom table presents potential outcomes for both the Horseshoe Hill 11-22H-1 and the Lewis 30-19H-1. I used the "factors" from the Goodrich Blades 33H-1 well.  Utilizing the "per 1000 foot" factor, the Horseshoe Hill calculates to be 1930 boepd and the Lewis to be 1644 boepd.  Utilizing the "per stage" factor, the Horseshoe Hill calculates to be 2032 boepd and the Lewis to be 1651 boepd.  These are very impressive rates and I believe that they are achievable.  These factors are treating all locations as "geologically equal" which they are not.  The Lewis well has very similar log properties as the Blades 33H-1. The Horseshoe Hill is over 30% thicker than the Blades, so who knows what impact that might have.  As more wells are drilled, it will be possible to tightly correlate results with these geological parameters.  Six wells do not provide enough control to make projections with significant confidence.

Tuesday, May 27, 2014

TMS Play History

As we enter this next phase of the Tuscaloosa Marine Shale Play, it's interesting to look back to the beginning of this latest era.  The chart below displays key events in the play along with the cumulative wells drilled.  The play has recently crossed the 50 well threshold.

Sunday, May 25, 2014

Current Well Activity

There are currently 15 wells in "play" either about to spud, drilling, waiting on completion, fracking, or flowing back.  Many results will be announced over the coming weeks.

Current Active Wells (red)

Friday, May 23, 2014

Emerging Shales Conference

I, along with Goodrich Petroleum, will be presenting at the Emerging Shales Conference next week in Houston. I look forward to visiting with many of you then.

Wednesday, May 14, 2014

Encana Earnings Call

The TMS highlights from the Encana earnings call:

  • Our 2014 drilling program in the TMS has been largely successful year-to-date. As the last three wells, one Encana operated and two non-operated brought on production are meeting or exceeding our expectations and normalize for a 1,000 foot lateral length basis. We are currently operating two rigs in the play. During the quarter, we entered into an agreement with a third party to help accelerate our evaluation of TMS. We still hold approximately 200,000 net acres in the play with an average working interest of 91% where we are focused in the central and eastern portions of our original land base. This allows us to realize some immediate value from our large land holdings in an area and focus our activities on areas where we can best develop rather than having to drill wells for simple land retention. 
  • Recently we have seen significant drilling ramp up by industry in the TMS. This is good news for us because having multiple companies operating in early life resource play, accelerates the appraisal and assists in unlocking its full potential. 
  • Jeffrey Campbell - Tuohy Brothers Good morning. The first thing I wanted to ask is if you could remind us of your expectations for the TMS that were exceeded in the most recent operated and non-operated wells? Doug Suttles - President & CEO Thanks Jeff. I will ask David Hill, who is our EVP for Exploration and Business Development to pick that up. David Hill - EVP for Exploration and Business Development Excuse me, hi Jeff. We have one well that's on here in the first quarter and that well is continuing to perform with us on the type curve and two other wells that are non-operated by Encana, also continue to hit the type curve. So these are the first three well that have had significant production in the first quarter. So we are very encouraged at normalized per thousand foot that these well are hitting type curve for us. 
  • Brian Singer - Goldman Sachs Great. Thank you. And then lastly following up on the Tuscaloosa Marine Shale question earlier, when you mentioned your operating well was performing above expectations, can you just remind us what your base case is, that is perfuming above in terms of well cost and well performance? Doug Suttles - President & CEO Yes, regarding performance, again early days, less than -- right around 30 days on production, but the type curve that we are seeking to achieve here is about 730 million barrels and from well cost perspective that's an early well, so we aren’t really comparing well cost to our RPH method at this time, but we are really focused in on well performance.

Tuesday, May 13, 2014

Amelia Resources Announces Data Room Opening

THE WOODLANDS, Texas--()-- 
Amelia Resources LLC announces the sale of 138,000 net acres in the Tuscaloosa Marine Shale play.
“The initial potentials, production volumes, and decline curves indicate large recoverable reserves in the range of 400-900 MBOE. The play economics, consistency of the reservoir, and resulting reserves will make this a very competitive play for years to come.”
Amelia Resources announced today that it has been retained as a technical consultant to host a data room to market 138,000 net acres in the Tuscaloosa Marine Shale (TMS) play. The data room will open on May 19, 2014.
Amelia's President, Kirk Barrell, said, "Recent results have created a lot of interest in the TMS play. Drill times have greatly improved along with a decrease in associated costs. We’re excited to have the opportunity to market the only remaining large aggregate block of acreage in the play. We believe that the repeatability and economics of this play will be extremely competitive with other U.S. oil plays.”
With 23 years of experience across the Tuscaloosa Trend, the company has evaluated over 1,000 wells in the TMS across Louisiana, Mississippi, and Texas. Utilizing a diverse dataset of well logs, geochemistry, seismic, and petrophysics, the company has confirmed and defined the most economically attractive areas of the play.
Amelia’s clients have secured large acreage blocks spread across the heart of the play. Barrell stated, "The initial potentials, production volumes, and decline curves indicate large recoverable reserves in the range of 400-900 MBOE. The play economics, consistency of the reservoir, and resulting reserves will make this a very competitive play for years to come."
Amelia Resources LLC is a privately held exploration and production company. The company generates drilling prospects and is actively engaged in several projects across the onshore Gulf Coast. Amelia was founded in 2003 by Kirk Barrell and has offices in The Woodlands, Texas, 30 miles north of Houston. The company leverages its 27 years of geological and geophysical experience to obtain strategic positions in drilling projects. Updates on the TMS and Austin Chalk projects are provided by the company at
CAUTIONARY STATEMENT: This press release contains certain forward-looking statements regarding various oil and gas discoveries, oil and gas exploration, development and production activities, anticipated and potential production and flow rates and the economic potential of properties. Accuracy of these forward-looking statements depends on assumptions about events that change over time and is thus susceptible to periodic change based on actual experience and new developments. Amelia Resources LLC cautions readers that it assumes no obligation to update or publicly release any revisions to the forward-looking statements in this press release and, except to the extent required by applicable law, does not intend to update or otherwise revise these statements more frequently than quarterly. Important factors that might cause future results to differ from these forward-looking statements include adverse conditions such as high temperature and pressure that could lead to mechanical failures or increased costs, variations in the market prices of oil and natural gas, drilling results, unanticipated fluctuations in flow rates of producing wells, oil and natural gas reserves expectations, the ability to satisfy future cash obligations and environmental costs, and other general exploration and development risks and hazards.


Amelia Resources LLC
Kirk A. Barrell, 281-798-6741


Friday, May 9, 2014

Halcon Earnings Call

Halcon had their earnings call yesterday. Here are the highlights:
"We're looking for big ass results. I don't know what else to say."
Floyd Wilson, CEO, Halcon Resources

  • have over 316,000 net acres in the play
  • off to a solid start, drilled our first TMS well in Wilkinson County, Mississippi, a bit ahead of schedule and in about 39 days. It was a 21,171-foot TD with a 7,751-foot lateral. Completion operations are currently underway. 
  • confident we can reduce the drilling days by year end by 15% to 20%. 
  • drilling our second well now, the Black Stone minerals well, and we'll move in the second rig within 10 days or so. 
  • continue to evaluate joint venture or financing options for the TMS. 
  • This is 100% about balance sheet management and future rig count growth opportunities
  • we and a few others guide this play into its place as a-- one of the premier large-scale crude oil-based resource plays in the United States. 
  • Our excitement for the TMS continues to build.
  • If we decide to bring in a financial partner to assist in financing our TMS activities, the liquidity would, of course, be further improved by that transaction.
  • Lease acquisitions, seismic and infrastructure came in at $128 million for the quarter. Most of the spending was related to growing our acreage position in the TMS
  • we fully expect to reduce drilling days, which is the first win in any of these horizontal plays, by 15% or 20% through the course of the year. I notice that one of our peers in the play has reported that they expect to drill their wells in less than 40 days, assuming no major trouble. We are planning on this sort of timing, but we would expect to beat it, of course. On the cost side, we're walking into this thing as we do in any new play with full analytical planning in place in terms of tools, logs, pilot holes, whatever we think we require. Our initial feel for the play is that we'll drill most of our wells, first few wells, for about $13 million. We think we can get that down about $1 million a year, each year for a couple of years. And our thoughts haven't changed along those lines.
  • We would only do a deal that's attractive to us. And it's just one of the things that we have determined that would be appropriate for us to review for this play. Our plans for 2014 and our current plan for 2015 will be unchanged in the absence of any kind of a new JV or some sort of financing of that type. The only thing that might happen, we might ramp up a bit quicker at the end of the year and into '15, and that's just -- and by the way, that's all based more on results than it is on money. We're well equipped right now financially to deal with this play. And we're well experienced, as you know, in this kind of thing. So the results are the first thing. We've got plenty of money right now. Ramping up is an objective, but it's an objective based on results.
  • there's been a lot of wells drilled already, and we have the benefit of the learning curve that they've gone through. So right now, we feel like we have a good recipe down on the drilling side, and others do also. You're seeing every month, people come out with record drilling days -- time for drilling days. And we're right there with them, and we expect that trend will continue. But we don't see radical changes in the overall design of where you're setting casing and what you're targeting. That's kind of getting locked in for everybody right now. The completion side, like all of these plays, is probably where you have a little more room to tweak the designs a little bit to get better and better results.
  • we're drilling 20,000-21,000-foot wells every day in the Bakken. So those 2 backgrounds are a perfect fit for the drilling in the TMS. And then on the completion side, yes it is similar to what we're doing over there also. And so we're taking that learn and combined with all of our hundreds and hundreds of wells we previously did in the Eagle Ford throughout the whole trend, and we expect to hit the ground running on that front with this first well.
  • We've programmed the drilling and the completion for optimal -- at this stage of the game, optimal IPs and frac jobs that last, and we've equipped the wells appropriately. So we don't really have a formula. It seems to be that with the lateral this length and absent any completion problems, we should expect a really attractive -- certainly, an IP and a 30-day IP, but it's a little bit out in front of us here. To meet the type curves that we've proposed and to meet the type curves that some of our industry partners are using, you need a fairly stout start to make those work and others are doing it, and we expect to meet or beat our own expectations.
  • Leasehold: We have the amount that we spent on the TMS, that was about $63 million

Wednesday, May 7, 2014

Goodrich Petroleum Earnings Call

The highlights from the transcript of the earnings call:

-currently operating 3 rigs 
-As many of you are aware, the early wells drilled in the optimal lower landing target experienced drilling problems related to wellbore instability and a specific interval of the TMS just above the lower target. To mitigate these early time drilling challenges, we've revised our go-forward plan of drilling this unconsolidated or rubblized zone at approximately a 70-degree angle rather than the 80 to 85 degrees, as many of the early type wells have been drilled. While a 10 to 15-degree change in angle may not sound like a lot, in reality, we have reduced the area of traverse or contact with the unstable, highly consolidated or rubblized zone from approximately 135 feet of contact to just 25 feet. This change has dramatically reduced wellbore instability issues and allowed us to drill this section and land in the lower target without significant drilling problems. 
-Our recently completed wells, the CMR 8-5 and Blades 33-1 were drilled in this manner, as were the 3 most recently drilled wells, where we have recently moved into completion mode on the C.H. Lewis 30-19, Nunnery 12-1 and Beech Grove 94-1 wells. We believe this is the right template and is our design and plan going forward. 
-By landing in the lower target and reverting back to standard drillable composite frac plugs, we've also been able, thus far, to eliminate any of the issues we and others experienced previously with casing deformation and difficulty drilling out frac plugs when landing in the upper target. This process and completion design worked well on the CMR and Blades wells and will be the same procedure used on the Lewis, Nunnery and Beech Grove wells, each of which we expect to be completed by the end of this month. 
-Our recently completed Blades well was significant for a number of reasons, including as a delineation well, as it is the most southeastern horizontal TMS well drilled to date. Likewise, our upcoming completions will also be important as the Nunnery will be the most northeastern well on the play thus far, and our Beech Grove will be the most southwesterly well drilled using our completion design. The completions of these wells and our increased phase of development with 3 rigs running, as well as the increased level of industry activity, is advancing the development and delineation of the play at a significantly faster pace than even a few months ago. The faster pace of development is a benefit to all operators in the play, and I expect we will soon cross the milestone mark of 50 modern-era horizontals drilled by the industry in the TMS. The increased activity is also advancing the ball faster towards full delineation of the play, moving us to or very close to an inflection point in the play's development. With the play's inflection point upon us, our current plans include the initiation of a joint venture process in the TMS in the second half of this year, which would include bringing in a new JV partner or expanding our existing relationship. The next few months will be very interesting and exciting times for the TMS. And now I'd like to turn the call over to Rob Turnham. 
-we tweaked our completion methodology on the Blades, which was a 5,000-foot lateral, by reducing the frac interval and slightly increasing the profit amount per stage, which yielded a higher production rate per linear for the lateral. 
-when you analyze core and other subsurface data, we only see minor differences in the rock quality across our entire block and the difference in well results are primarily been driven by landing target and completion recipe. 
-We continue to update production from the key wells and plot against our 600,000 and 800,000-barrel type curves 
-we own a non-operated interest in a couple of wells where pump depths and size of pumps have been adjusted, yielding much better rates and flatter profiles in further support of our type curves and approximately 2 years of production 
-Well cost in the play will continue to come down as we shave days off of our drilling curve, get more competitive pricing from service companies with increased capacity in the field due to higher activity levels, and pad drilling, which we expect to begin on a limited basis shortly. Depending on lateral length and number of stages, we see a path to a potential $11.5 million completed well cost by the end of the year and further reductions next year towards our target of $10 million in development mode. Also, with the added activity from other very capable operators in the play, we will each benefit from each other's activities as we're sharing information with a common goal of best practices as soon as possible. To that end, you will see other operators with very good drill times on recent wells, and we expect that to continue. 
-we will be in a position to entertain JV options in the second half of the year -We're currently frac-ing our C.H. Lewis well which is 6,600-foot lateral with 26 planned frac stages. We will put our Blades completion recipe on the well. 
-We're also scheduled to frac our Nunnery and Beech Grove Wells in May. 
 -We are currently drilling our SLC well in West Feliciana Parish, Louisiana 
-plans to commence drilling operations in the coming days on our Bates and Denkmann wells in Amite County, Mississippi. 
-the Blades well at 5,000-foot lateral, clearly, as you can see, it's currently tracking our 800,000-barrel curve 
-our CMR is probably more closely tracking our 600,000-barrel curve -update of our 600,000-barrel curve with the 2 oldest wells, the Anderson Wells. They've tweaked the artificial lift a bit. Those production rates are up and back up like where we thought they would be or sitting right on top of our curves 
-we'll start to see some of the economies of scale from pad drilling sooner rather than later
-we're going to be back up in the Crosby area, Foster Creek, Crosby area in Wilkinson County. And we have a plan for a 2 well pad up there. The benefit of the 2 well pad is, obviously, from a cost standpoint. But you form these 3 section units. You put the pad in the middle. You drill a tow-up well and a tow-down well and, obviously, capture acreage a little bit quicker, but forget the benefits of the cost reduction. So that -- the 2 wells will be -- we'll have several of those in 2014. And then, the multi-well pads will commence in 2015. 
-we're thinking that ultimately it could be 80 100-acre spacing, but we're probably thinking 160-acre spacing initially. So call it 1,320 feet between well bores or 4 wells per unit. And that would be -- we think we'll down-space from there in the future 
-the next few wells are planned to pump about 550,000 pounds of proppant per stage. As we've said before, we are targeting about 6,000 plus feet of lateral. As Rob said earlier, we think that longer laterals is the better way to go, but we're very, very mindful of cost per well at this point. And we don't have the full answer to how much incremental reserves a longer lateral with a similar type completion design would yield. So we're going to kind of target that 6,000 plus and let each well be dictated upon exactly what happens as we get at or around that 6,000 foot of lateral and try to be mindful of not spending extra days unnecessarily. And -- but you can think about us being plus or minus around 6,000 for the next few wells 
-I think the Blades well was 36 days. Obviously, that was kind of 9 days under AFE 
-A lot of our improvement, we think, is going to come in the vertical portion of the wellbore. We can, as Gil said, reduce the flat spots when you're running casing, drill the vertical well faster, increase your rate of penetration drilling curve. We've been pretty pleased with the lateral drilling. Knowing that you're -- we're staying within a 10-foot window, you can only push the rate of penetration so much. So I think our improvement comes in the vertical portion of the wellbore. With the increased activity level, we are already seeing more bids. And of those bids, they're more competitive. And I think that only increases with the increased rig count in the field. So we're expecting to see a reduction in costs, I would say, other than our frac costs, which are basically locked in for 2014. And those are about 20,000 the stage less than where we were in 2013. 
-for every day you shave, it's a $100,000 off the drilling curve. The other goods and services we think are going to contribute quite a bit prior to pad drilling 
-we have used snubbing units to drill out frac plugs in the last couple of wells. We think that's the safer route to go. However, we've also seen a couple of wells recently that were not Goodrich-operated wells drill out their frac plugs successfully using coiled tubing, which we have done before, our Crosby well was of coiled tubing. I think, ultimately, you're going to see us move towards coiled tubing drill out. We -- admittedly, we're a little gun shy after the problems that we had. We want to put belt-on suspenders and we've done the last couple of wells of coiled with that with snubbing units. Yes, we are monitoring very closely the maximum treatment pressures to make sure we don't do anything that might put undue stress on the pipe to further mitigate pipe deformation. We happen to believe that most of that, however, when we look at the data across all of the wells that have been drilled so far, is really more around landing target than necessarily maximum treating pressure on any given stage. But that being said, we're trying to stay at about 1.0 gradient on our treating pressures 
-the only wells that have had any problems at all thus far, David, drilling out plugs have been upper target wells. About 65% of the upper target wells have been drilled in the play, thus far it had some degree of difficulty getting plugged up. And that would be in a combination of both snubbing unit drill-outs as well as coil tubing. We don't think that, that will determine. Determine is whether or not you deformed your pipe in any way shape or form. And if you have and you've done it to a strong degree, it probably doesn't really matter whether they're using a snubbing unit or a coiled tubing if you can't get down the pipe lateral -we're targeting the 6,000-foot laterals. And we think we can get to that number with multi-well pads, zipper fracs, all those things that we mentioned. So yes, we're still targeting the 6,000-foot laterals. Ultimately, we think we can get there to $10 million just -- and still get the full lateral length. 

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