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.

http://www.emerging-shale-plays-usa-2014.com/

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 www.tuscaloosatrend.blogspot.com.
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.

Contacts

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

SOURCE: 
http://www.businesswire.com/news/home/20140512006747/en#.U3Jg9_ldWAk

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. 

Entire transcript:
http://seekingalpha.com/article/2195643-goodrich-petroleums-gdp-ceo-walter-goodrich-on-q1-2014-results-earnings-call-transcript

Tuesday, May 6, 2014

Earnings Calls

Two earnings calls today

Goodrich:
http://edge.media-server.com/m/p/gedsehk9/lan/en

Comstock:
http://phx.corporate-ir.net/phoenix.zhtml?c=101568&p=irol-eventDetails&EventId=5128119

Goodrich TMS Highlights:
-The Company is currently fracking its C.H. Lewis 30-19H-1 (81.4% WI) well in Amite County, Mississippi, which was drilled in 36 days and will have an approximate 6,600 foot lateral with 26 planned frac stages. The Company will use the same enhanced completion design of reduced frac intervals and additional proppant per stage as used on its last well drilled in the TMS;
- The Company has recently moved into completion operations on its Nunnery 12-1H #1 (94.1% WI) well in Amite County, Mississippi and its Beech Grove 94H #1 (66.7% WI) well in East Feliciana Parish, Louisiana, with plans to frac both wells in May; 
-The Company is currently drilling its SLC, Inc. 81H-1 (66.7% WI) well in West Feliciana Parish, Louisiana and will commence drilling operations on its Bates 25-24H #1 (97.6% WI) and Denkmann 33-28H #2 (75% WI) wells in Amite County, Mississippi in the coming days.
Source:
http://phx.corporate-ir.net/phoenix.zhtml?c=83169&p=irol-newsArticle&ID=1927218&highlight=

Comstock TMS Highlights 

The budget for drilling activity includes $284.0 million to drill sixty-five wells (46.0 net) in the Eagleville field in South Texas, $79.0 million to drill ten Eagle Ford shale wells (9.2 net) on the Burleson County, Texas acreage and $33.0 million to drill three wells (2.7 net) targeting the Tuscaloosa Marine shale.
Source:
http://phx.corporate-ir.net/phoenix.zhtml?c=101568&p=irol-newsArticle&ID=1927076&highlight=

Halcon tomorrow:
http://investors.halconresources.com/releasedetail.cfm?ReleaseID=840951