Replies to This Discussion

Permalink Reply by William Burch on May 12, 2011 at 7:51

$13+M for a CO2 is one damn expensive investment.  It would be much cheaper to set up a CO2 plant in the area for the EOR requirements than drill for CO2.  There's no way Mainland would keep the well active if it's flowing CO2.  Plus, at ~800 psi, CO2 liquifies.  I suspect the stainless tubing they've ordered from Japan is in anticipation of high carbonic acid production which would kill regular grade tubing if they were to put the well on long-term production.

 

As an aside, does anyone know what rated wellhead and Xmas tree they put / plan on putting on the well?  15k (I'm assuming?)  The reason I ask is that you are all aware of the 20,800 psi pore pressure but if you subtract a 0.104 psi/ft natural gas gradient (at worst case of course), that's only 2,000 psi which means that in the event they have to shut in the well (which they better be able to or else my regular job is going to be real busy), that puts 18k at surface.  The casing they ran at surface (9-5/8) doesn't anywhere near enough burst rating to withstand a tubing failure meaning you're talking a relief well and $$$$ in well control costs.  Is the MS O&G board aware that they wouldn't be able to shut in the well during the flow test unless they upgraded to a 20k or better Xmas tree? Or, if they actually get a 20k Xmas tree (which there isn't many of them laying around these days and there is only 1 25k Xmas tree in the world - Davy Jones #2 has that already) and they have a tubing failure, they're in deep trouble regardless?

 

Again, while I hope for the land owners and neighbors this well is a boon to the area (sincerely I do!), technically Mainland is in WAY over their heads and that should be a screaming red flag to investors.  If this was Chevron again, then I'd say yes - they have a team of HP/HT production engineers and EXPERIENCE behind them in managing wells like this (not shale though...)  But Mainland isn't Chevron - it's a couple of guys out of the Woodlands with some capital.  Yes, McMoRan has drilled some wells in the GOM that were boundary breakers but they also have a gigantic mining operation to afford their screw ups.  Again, just my observations from the outside...

Permalink Reply by Bob Nies on May 12, 2011 at 9:44

No one drills a wildcat for CO2, but the well is drilled.... if the high temperature/pressure completion is mostly or all CO2, and capable of 10-30 MMCFPD, then there would be a local market for enhanced oil recovery.... that could be a small bail out and could recover all or a part of the already spent money for drilling and completion testing. 

 

All of these things will sort themselves out in the next 3 or 4 months..... patience is a virtue....

Permalink Reply by Flip Phillips on May 13, 2011 at 4:10

I sent your comments to someone very familiar with the area, the old Chevron well and the current well. His comments are included in the attachment. Without be defensive and/or competitive, would you care to comment on them?

Attachments:

• mainland info.pdf, 254 KB

Permalink Reply by William Burch on May 13, 2011 at 6:44

Flip,  I'm not defensive and certainly don't hope that I come across as such. Trust me, I've eaten enough crow working the oilfield over the last 11 years that I'm starting to enjoy the taste of it (of course with plenty of Tabasco.)  :-)  Good technical arguments is my kind of day!  My comments come from the various roles I've had in the business and if you want to know more about what I've done, let me know outside of this forum.

 

Although I haven't been a mudlogger, I'm well aware of the pros and cons of mudlogging as I've sat countless hours next to them in the LWD/MWD unit.  For someone to say I'm not aware that there was mudloggers on the rig or the value they bring to formation evaluation is ridiculous.  My comments about CO2 are from anecdotal stories from colleagues of mine in Houston, but if you go back and look at several of the offset ultra-deep HP/HT wells in the GOM shelf and S. LA, they had mudloggers too and positive shows.  Otherwise, why would the majors have spent all that money on well testing and completions?!  However, when a few of these prospects were well tested, the well flowed more CO2 than dry gas and the projects were deemed non-commerical.  Is there the possibility that Hanyesville in this interval can flow gas?  Yes absolutely.  Commercial quantities?  Maybe.  It'll all depend on the frac efficiency, frac half lenghts, and pressures before screen out.  Is a stimulation job at 22,000 ft with PP=20,800 psi normal?  Hell no.  I'm fascinated to see how they're going to engineer this stimulation job and how much of the Hanyesville they plan on vertically stimulating.  I wish Mainland would have cut more core across the Haynesville and rely less on a extrapolation of a 40ft core to a 2000 ft section.

 

The one thing that keeps bothering me about the economics of this project is that the shallower Hanyesville plays in N. LA according to a new 130 well study have a P50 production life of 12 months.  Correlations are now being seen among many of the shale gas well plays (especially in Canada) that these frac jobs end up closing (or crushing the proppant?!?) if the well isn't put on production very soon after the frac.  So, put it in perspective - shallower, lower pressure and much easier to fracture longer horizontal Haynesville wells have a predominately short economic life.  Most of the big boys here in Houston are banking on $5Mcf gas and as no surprise are losing their ass - especially if running 50+ rigs and pipeline capacity isn't keeping up.  In addition, Mainland has limited gas infrastructure immediately available to sell the gas to market.  Can that pipeline nearby handle a 20MMscf/d sudden increease? If not, if will need 6 months (? - my guess only) to run additional pipe to connect to a major gas line after the stimulation job and flow testing - but will the well still be able to flow at the DST rates or does it close up like the shallower plays?

 

OK, looking at your calculations, I think your a little low on P and a little high on T but regardless, we get the same ballpark Z.  And, looking at the math, I'm also in general agreement with the recoverable.  However, where I disagree is with your approach of classic Bgi.  I don't believe that you can use 20% porosity and 25% water saturation for a shale.  Again, let me preface by saying I've never been accused of being a reservoir engineer.  But, a shale does not act like a sandstone when it comes to flow through porous media (the WORST graduate class I've ever taken.)  I don't know what is the industry standard for calculating gas in place in a shale nor how you can translate that to a simpler formula.  I'm happy to someone to teach me that!

Permalink Reply by Flip Phillips on May 14, 2011 at 0:01

Sorry William....just wanted to make sure you weren't trashing for the sake of manipulating. You obviously have experience in the field and are tapping into that experience. I have no experience in the field but I do have a small network of 'pros' who do have and those are the people I rely on and whom I pass on any info and concerns for their comments, (which I have done with yours and a few others). I appreciate your comments and it helps me to understand some of the opposing issues in my discussions with these guys. 

 

Granted, this is not a typical well......and there are a lot of variables involved....but I'm more optimistic based on what I am hearing. Sometimes less experience is actually a good thing. Heck, 20-30 years ago, no one knew how to extract gas from shale and Q&G people didn't pursue it because their experience told them it wasn't possible...until someone figured it out . And now they're all on board. New technology is advancing every day in this field so who knows what might be possible at 22,000 feet tomorrow. I'm confident that this area will eventually be very prolific.....and this well will be the starting point.  

 

Maybe it's best that we take this off line. Feel free to contact me at flip at stny dot rr dot com 

Permalink Reply by Skip Peel - Mineral Consultant on May 14, 2011 at 3:13

It is simply good business to seek and consider multiple opinions when making investment decisions.  It is tempting to limit input to those that espouse opinions that support the desired outcome and ignore or discount those who do not.  IMO, a number of participants in this thread have posted information and expressed opinions that should inspire a level of caution in regard to the MNLU, the BV prospect and the Burkley=Phillips well.  Mr. Burch is obviously knowledgeable but he also tells us what he feels sure of and the professional experience that makes him confident in his assessment and when he is speculating based on less direct experience.  His even handed replies, explanations supporting his assertions  and avoidance of personal attacks on those who disagree with his opinions are the preferred approach to debate on GHS.  IMO, there are no GHS members with an agenda to spread misinformation concerning this well.  Personal opinions vary, opposing views should be expressed for a balanced debate and discussion comments should not devolve into personal attacks.

Permalink Reply by Les Bamburg on May 14, 2011 at 4:44

William, calculating the OGIP for shale is really no different.  The key is arriving at reasonable values for input parameters such as porosity, water saturation, net thickness for each section (640 acres) not to mention determining the total areal extent fo the play.

 

By the way, don't be too quick to assume people are losing money on the Haynesville Shale play in NWLa/ETx.  You have to remember that most fo current production has been hedged at prices well above $5.00/Dth.  Plus, pipeline capacity to date has been more than adequate to handle the growth in natural gas production from the region.  The primary issue has been frac crews and equipment and that has improved this year. 

Permalink Reply by jeff boler on May 18, 2011 at 3:42

Flip,

For the calculations, I would assume a porosity between 16 and 18%. 20% is a good number for most shales, but this deep it would have much more overburden pressure trying to compact it. Yet, at the same time, it has a super high pore-pressure fighting against the compaction. Still, I would suggest a number below 20%. 

The water saturation will be but a fraction of 25%. I would suggest using a number between 4 and 8% water saturation. Remember, the absence of water is why the reserves were upgraded following the core sample results. Less water hydrogen-bonded to the surfaces of the shale grains has left more room for methane to bond to these surfaces and thus higher test results.

--

Another note: MNLU accessed the cuttings samples taken by Chevron from this interval of the C.P. Long et al #1 well. Despite 3 decades of sitting in a warehouse, MNLU's gas analysis of the cuttings would have let them know if high concentrations of CO2 were present.

Deep CO2 Accumulations in the general vicinity of this well are mainly associated with the Jackson Dome volcano. This trend tends be associated primarily with the Norphlet and Smackover Formations and form a trend originating in the Jackson, MS area and extending to the North-East. 

Permalink Reply by Flip Phillips on May 13, 2011 at 4:15

I sent your comments to someone very familiar with the area, the old Chevron well and the current well. His comments are included in the attachment. Without be defensive and/or competitive, would you care to comment on them?

Attachments:

• mainland info.pdf, 254 KB

Permalink Reply by Bob Nies on May 14, 2011 at 5:12

The reserves estimates were not made by MNLU, but by Schlumberger and Core Data, two well known and experienced industry experts. These are independent concerns who have determined gas in place and initial reserve figures.....

 

Final determination of recoverable gas is a long way down the road after completion attempt, CAOF, and production history (if any). 

 

Any guesstimate is just that, as Skip and others point out the proof will be in the pudding.... we all will place our bets on what we currently believe will be the outcome....

 

Some will be right and some will be wrong.... those building shares down here are betting for a high return... those staying away can bet somewhere else, but in the end isn't it great fun to see how this all works out.

Permalink Reply by jeff boler on May 17, 2011 at 21:42

CO2 and carbonic acid are the same thing. CO2, when dissolved into an aqueous solution exist primarily as carbonic acid, provided that the pH is below 4.2. Should the pH be increased to 4.2<pH<10.3 the CO2 will shift to the bicarbonate ion and at pH's above 10.3 the CO2 exists as the carbonate ion. Because CO2 is an acid gas, it tends form solutions with low pH's so carbonic acid is the most frequent form in nature.

 

I looked into the well-head issue last fall & found it very interesting that there were less than a dozen 20k christmas trees in the world... They won't be picking one up at the local bone yard, that is safe to say...

 

In the event that MNLU melts a completions rig, they will file bankruptcy. This well was drilled on 100% AEXP leasehold with MNLU the liable drilling operator. You can rest assured there will be no merger until after the well is on line and producing - why expose AEXP's assets (including the best 5000 acres of the leasehold & a $20MM well) to any liability. As things stand right now: MNLU cannot loose the well in the event of bankruptcy or lawsuit because it's not MNLU's well to loose, yet.

Permalink Reply by obed w odom on May 19, 2011 at 14:28

Is Mainland Resources undergoing a re-organization? Their stock symbol suddenly seems to have changed from MNLU to MNLUE. I can't find any news about it online, but a guy at E-trade says it appears to be a name change in progress, although he had no details. Thanks for any input.

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