Replies to This Discussion

Permalink Reply by Flip Phillips on February 23, 2011 at 11:50

OT.....Rusell, I sent the email and got no kickback so I assume that you got it.

Permalink Reply by rusell shleby on February 23, 2011 at 12:58

I have sent you 4 return emails, check your spam folder. If not ill try you from another email address.

Permalink Reply by Flip Phillips on February 23, 2011 at 13:02

nah...gettin nothin

do this: flip@stny.rr.com

gotta go for now....martini time...yippi yeh ciyo mf

 

Permalink Reply by Flip Phillips on February 18, 2011 at 8:25

BTW....is your well still active?

Permalink Reply by Buck Marshall on February 18, 2011 at 9:06

That pipe was ordered some time back, but don't know if they'll need it or not.  Thats something more typically associated with oil.  Our oil well was shut down when the price dropped, in '82? I think.  My mother got royalties for several years until the price dropped.  So I don't know whatever happened to it.

Permalink Reply by jeff boler on February 19, 2011 at 0:50

I believe that my last comment was misinterpreted, due to my poor writing skills. The point that I was pushing was that Chesapeake has no way of knowing how their North Louisiana Wells will be performing decades down the road. I was referring to Chesapeake's arrogance. It was not my intent to say that any participants of this board were arrogant for applying Chesapeake's estimates, though I don't think such an exercise would yield accurate numbers. That said, reservoir engineering is very similar to astronomy in that anything within an order of magnitude is considered close...

 

I agree with Paul that the natural fracture system is key to making the geology of the Buena Vista Project so attractive. The natural fractures as previously stated will provide excess storage capacity and permeability, both of which are quite valuable and rare in reservoirs of this type. Also, I speculate that the natural fracture system will provide a unique stage for a synthetic frac-job. The post-completion drainage basin for these wells could be quite extensive. 

 

The pore-pressure of the reservoir is another unique aspect which vastly increases storage capacity. The pores of the shale and natural fracture volume will hold more gas than it would under lesser pressures, as it is more compressed. It is important to remember that natural gas exists as a liquid in the reservoir, but liquid methane is a compressible fluid - If I remember correctly this is governed by the Rackett Equation. In addition to another means of increasing the reservoir storage capacity, the pressure will also push the natural gas through smaller pores and tighter fractures than would be possible under lesser pressures. This will also lead to an increased size of the well's drainage basin. 

 

The greater the size (volume) of the drainage basin of a particular well, the longer it will take for the reservoir pressure to deplete. This will lend for flatter decline curves with respect to production rates and fewer wells required to drain the reservoir. Also, a higher percentage of the 'Free Gas' will be recoverable.

 

In summary, both the storage capacity and size of drainage basins are going to be uniquely favorable to high, prolonged production. Fewer wells will be required to produce the leasehold, which will increase the profitability of the project.

 

I maintain that with all of the information avaliable to the architects of this project (everything from cuttings to well-logs), ground would have never been broken on the Burkley-Phillips#1 unless the numbers added up to profit. Profit at current gas prices...

 

 

Permalink Reply by Flip Phillips on February 19, 2011 at 1:59

That's very interesting, Jeff. I'll pass that around to the family. Thanks

Permalink Reply by Flip Phillips on February 19, 2011 at 3:26

Hey Jeff....you seem to have a grasp on the mechanics of share drilling....would you mind addressing a few more questions.

 

-Is 'choking' a wellhead for the purpose of slowing the flow when prices are low..... or for the safety limits of the head and/or the transporting pipeline, etc.

 

-The higher producing wells in Louisianna are in the range of 20-30MMcf/d. Is that pretty much the limit (safety or otherwise) for gas wells? IOW, if a well can produce 50MMcf/d, and the prices are higher, would a producer typically go that high? .....or are there other factors to consider in keeping the flow lower.

 

-Lastly (for now)......If Mainland finds that in addition to good reserves at 22,000ft, there are also good reservers in a higher section (say at 10,000 ft), would a company typically drill the next well at the higher depth due to a quicker roi?

 

Thanks

Permalink Reply by jeff boler on February 19, 2011 at 11:38

Mr. Phillips;

 

I like to think that know a little bit about drilling, but when it comes to many related topics such as completion, production, estimating reserves, etc. I only know what I have read, or deduced from just sitting around thinking about it (I have no life - only one day off since October & that was spent driving). I'll do my best to answer your questions, but please know that unlike Skip, I have been wrong before and I'm sure it will happen again...

 

Chokes-The best size for the choke is determined during the well-testing phase following completion. Operators evaluate current and forecasted natural gas supply, demand, and price to determine the overall production profile that is likely to produce the most profit (a lot now and rapidly declining production until a stable rate is reached, or a moderate amount now and a slower decline of the overall production). The choke serves as an orifice sized to maintain the desired pressure on the gas stream exiting the well-head. The valve that your garden hose connects to allows you to restrict the pressure of the water flow to do the same thing, only a choke is not as easily adjusted. Other considerations are also taken into account. I will list a few that could effect this project, but this list is not meant to be exhaustive. (A) Ideally the choke would be set to maintain the desired production rate while allowing for a near constant bottom-hole pressure (B) Excess capacity of pipeline network. In this case the existing pipeline is rumored to only be capable of handling 5 MMCF/day. (C) If the gas is wet, the choke is set so that the pressure drop across the perforations (where the gas exits formation and enters the well-bore) is low enough to prevent the 'wet' molecules from condensing into a liquid (everything should vaporize when entering the well-bore; methane, ethane, propane, etc.). Condensation would result in a column of condensate forming in the bottom of the well. A column of condensate would apply more and more hydrostatic pressure to the formation and coupled with the pressure restrictions in the choke would eventually be great enough to stop production and kill the well. This in very similar to water vapor condensing when it exits an air conditioning vent. Condensate production is a good thing, increasing revenue, but you want the condensate to condense once at the surface, not in the well-bore. (D) The likelihood for water-coning is estimated, and if the operator feels that the well is at risk of experiencing water-coning, they would consider restricting the flow more than the well might be capable of flowing. Water-coning is when the lower pressure in the well-bore encourage the oil-water or gas-water contact to migrate toward the perforations and eventually water production will increase, possibly killing the well. Once water production becomes an issue, it is irreversible. Capillary forces within tight reservoir rocks suck up water like a sponge, resulting in the formation that is impermeable to hydrocarbons, though water flows freely through it. Water-Coning will not be an issue in the Burkley-Phillips#1 Well.  (E) Safety, as if left un-choked, the pressure would be more than most surface piping/processing equipment could withstand. I'm sure that in the case of the Burkely-Phillips#1 Well, all processing equipment, piping, and eventually the new pipeline will be sized to maintain whatever the maximum flow-rate that the Mississippi Oil & Gas Board deams appropriate following the well-test. 

 

Petrohawk has a number of North Louisiana Horizontal Wells that it claims to have put on smaller chokes in order to recover more reserves over the long haul. Unfortunately, this is not true. During the well-test, these wells proved inferior to all other wells horizontals drilled by Petrohawk and their competitors. Petrohawk determined that mistakes were made during the completion process due to cost cutting. Rock properties were used to design the frac-jobs that did not remain consistent over the entire arial extent of North Louisiana's Haynesville. I remember Petrohawk frantically drilling vertically 150 ft into the Smackover so that they could run a whole suite of logging tools (150' of logging tools) into the hole and still be able to fully log even the last foot of Haynesville. They did this on several wells all a once; making sure that their data was accurate for subsequent frac-jobs. I have since looked at the type-curves of production from some of these wells and it definitely appeared to me that these wells would eventually surpass the production of their more 'successful' completions, so Petrohawk's mistake might have allowed them to discovery a nice little trick.

 

Production Rates - There are numerous gas wells in both deep and shallow water GoM that produce 160MMCF/day. I don't think there is an upper limit on what can be safely produced. If a discovery is capable of huge production rates, operators will build/size the casing, wellhead, and surface equipment to handle it.

 

All wells have a cost associated with production - what it cost to keep things running. When prices drop enough so that the daily production is nearing the daily operating cost, Operators start thinking about shutting the well in. It should be noted that these wells can be tricky to get back going again, and a shut-in could totally kill a well for good. So a total shut-in can be risky, therefore if possible operators will try and keep the wells going, if possible. As mentioned above, operators will try and implement a production strategy to obtain the most profits

 

Shallower Pay-Zones - I'm sure that MNLU found oil &/or gas when they drilled through the Tuscaloosa Sandstones at around 12,000 ft, and the Tuscaloosa Marine Shale is saturated with oil. I have looked into both and unfortunately, these sands are too depleted to be profitable and no one has been able to unlock the potential of the Tuscaloosa Marine Shale as of yet. I'm also sure that a number of traps & reservoirs were penetrated in the Cretaceous, Hosston/Travis Peak, and Cotton Valley, but if they had been large enough to produce a profit, we would have heard about it by now. You're/Our best bet looks like it's going to be the Jurassic Shales, namely the Bossier/Haynesville which are no doubt what MNLU's 2000ft of shale can be attributed to. I have been on deepwater wells that logged around 1700 ft of consecutive Bossier-Haynesville shale at similar depths, so 2000 feet isn't hard to imagine.

 

And you never know, one day someone might find a big discovery in the Smackover, or Norphlet associated with the Buena Vista structure. I would think of all the shallower shows as $ in the bank, because one day the world will need all the gas they can find. If the Good-Lord blesses you with a long enough life, then one day someone will be knocking on your door wanting to grab those reserves, and at that time who knows what the price will be. In the more near term, I expect that you can count on a long steady income flow from MNLU's Bossier/Haynesville production - It's downthere...

Permalink Reply by Flip Phillips on February 19, 2011 at 12:18

wow...above and beyond what I expected...thanks a lot. You gave me plenty of 'Cliff Notes' info for me to follow up on. I had no idea how much went into production decisions.

 

"Your/our best bet......" How are you involved with this project.? (btw, if you would prefer a more personal conversation, let me know).

 

I would love to see this project come to fruition...who wouldn't. I'm retired and perfectly happy with my lifestyle but a few extra $$ would be just fine....so if this isn't the time, it won't be the first time. That being said, I've got kids and grandkids who might some day do well...so as long as there remains interest in the Buena Vista area...that's a good thing.

 

I live on the NY/PA border. I happened to be driving into the back hills of northern PA today and saw my first gas well!! My wife had no desire to stop but I would have stopped and watched all day...and let her take the car home...if I could have found an hour ride home. I LOVE that stuff!    

Permalink Reply by jeff boler on February 20, 2011 at 15:37

At the present, all of my worldly possessions can be summed up in the following sentence: I own a 4-runner full of junk and a few shares of MNLU, AEXP, & LNG (primarily AEXP).

 

I have a very good reason to speak well of these stocks to try and influence the price upward. But with no outgoing bills and invoicing for 30 days/month I am able to increase my position every time I get a payday. Therefore; it would be far more beneficial for me to attempt to influence the price down until the inevitable increase takes place. I have no agenda, and if I did it would be to talk poorly of MNLU/AEXP in efforts to purchase future stock at a reduced rate.

 

My purpose for participating in this discussion is pure science. I should also add that I post here because I enjoy talking about my industry. 

Permalink Reply by jeff boler on February 19, 2011 at 19:24

Here is a well log of a similar Bossier-Haynesville Shale interval. I have been looking back over it tonight and a few things jumped out at me that I had never seen before... I annotated the log with my thoughts and if anyone is interested, I have attached it below,,,

Attachments:

• Bossier-Haynesville(Annotated)20Feb2011.pdf, 930 KB

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