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.