Replies to This Discussion

Permalink Reply by CRAIG TAYLOR on February 24, 2011 at 7:24

William, could you please explain how a RA investment works? this is all new to me Thanks

Permalink Reply by 1sk58mq3tyx9y on February 24, 2011 at 8:24

My "RA' is Royalty acres. I think it best for you to query it on the net.

Permalink Reply by J Jones on February 24, 2011 at 8:55

My guess is that the investor owns part of or all of the mineral rights associated with the property, but not the property itself. 

Permalink Reply by 1sk58mq3tyx9y on March 1, 2011 at 6:27

Any info here from anyone would be appreciated. I own RA's in 10N-R1W. It's location is on Black Creek Plantation about three miles east of the Burkley-Philllips #1. The land owner sold most of the RA's to Mainland and kept a few for himself. He then sold some and mine were purchased from the part of those he kept. On the attached map Mainland owns 22.06% of Tract F. This is where my part of the RA's are located. If Mainland drills a well on thier portion of these does that mean that I will be a part of it? I find RA's to be a bit confusing.

Attachments:

• Mainland Royalty Acres Location.JPG, 323 KB

Permalink Reply by Skip Peel - Mineral Consultant on March 1, 2011 at 8:41

William, all leased mineral interests (including RA owners) within a drilling unit will receive royalty on their proportional share of production based on their percentage of  net mineral acres in the unit and the terms of their lease.  If MS provides for units based on sections as LA does, each unit will consist of approximately 640 acres.  There may be a number of unit wells drilled in a unit based on state well spacing requirements. The general concept of "pooling mineral interests" is used in all state mineral codes with some variance as to details.  You may wish to look through the MS mineral codes to find answers or for help in asking specific questions.  Link follows:

 

http://www.ogb.state.ms.us/docs/RuleBook20090403.pdf

Permalink Reply by ledlights on February 21, 2011 at 8:20

Jeff,

 

My take on the discussion - there have been a number of contributers who have counseled caution regarding MNLU due to a documented history of misrepresentation concerning their participation in the Haynesville shale.  Some have taken that history as reason to dismiss MNLU completely; others have just reminded everyone that such behavior is a legitimate red flag.  I believe that some of those "Cassandras" have a ton of experience and skin in the game, so I think they should not be lumped together as "closed minded" or in any way a drag on industry progress.  On the contrary, I hold companies that do not represent themselves accurately to be a much greater risk to such progress.

 

When this discussion is couched in black and white terms of us against them and you sound to me like a true believer who can hear no honest words of caution, then I think  it is you who is displaying the greater degree of closed mindedness.

 

I wish I had a penny for every buck (or every hundred bucks) that has been invested and lost on oil and gas wells that were "sure things" in the minds of very knowledgeable insiders.  Don't be so ready to dismiss the judgement based on hard-won experience that some of the folks here have been offering for free.  It is my personal opinion that no matter how successful MNLU ultimately winds up being, that the criticism of MNLU's self-representation has been valid and worthy of attention. 

Permalink Reply by Dennis Dion on February 22, 2011 at 2:22

All major energy cos. want shale gas reserves  BHP buys into U.S. shale gas play

19:27 EST Monday, Feb 21, 2011

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CALGARY — BHP Billiton Ltd. made its first move into unconventional natural gas in the United States on Monday, snagging a slice of one of the country’s largest gas fields in a multi-billion dollar deal.

The company has agreed to fork over $4.75-billion (U.S.) for Chesapeake Energy Corp. ’s stake in the Fayetteville shale. In doing so, Chesapeake is bowing out of that prolific zone in order to reduce debt.

The deal gives BHP, a global mining giant, a win after its proposed $40-billion takeover attempt of Potash Corp. of Saskatchewan was rejected by the Canadian government in November, and after its proposed iron ore joint venture with Rio Tinto could not overcome regulatory hurdles in October. It plans to pay for the deal using some of the $16-billion war chest of cash it has in the bank.

Major energy companies have been making moves in unconventional natural gas plays, buying themselves decades worth of production at a time when low gas prices have made it difficult for smaller companies to survive or extract all the energy under their control on their own. The transaction will make BHP the second-largest player in the Fayetteville shale, the company said.

The asset purchase “will immediately make BHP Billiton a major North American shale gas producer,” Michael Yeager, the head of BHP’s petroleum division, said in a statement. “It provides access to a competitive, long-life resource basin that benefits from our ability to invest through the economic cycles.”

The sale includes 487,000 acres of shale natural gas properties in Arkansas, as well infrastructure such as pipelines. The Chesapeake assets produce about 415 million cubic feet of natural gas equivalent per day, and will put an additional 10 trillion cubic feet of natural gas under BHP’s control. This will jack up its net reserve and resource base by 45 per cent, the company said.

Chesapeake will provide “essential services” for up to one year as Australia’s BHP takes over the property, the Oklahoma City-based company said. Producers use multiple horizontal fractures to extract natural gas out of shale rocks, a relatively new technique that has opened up new oil and gas plays. “Longer term, the expertise we gain here will be usable elsewhere as we continue to grow our business,” BHP’s Mr. Yeager said.

Chesapeake, faced with debt and operating in fields that require plenty of cash, in October struck a $1.1-billion joint partnership with China National Offshore Oil Corp. on some of its energy properties in Texas.

Chesapeake was advised by Jefferies & Company, Inc., while Scotia Waterous worked for BHP.

While Chesapeake is getting out of the Fayetteville play, it still operates and holds positions in four of North America’s most celebrated shale natural gas fields: the Haynesville, Bossier, Barnett, and Marcellus.

Further, a string of recent announcements highlight how difficult it is to produce natural gas in shale rocks unless companies have strong balance sheets or rich partners. Nexen Inc. last week said it was looking for partners for its shale assets, Encana Corp. two weeks ago struck at $5.4-billion joint venture deal with PetroChina Co. Ltd., and Talisman Energy Inc. in December made a $1-billion deal with South Africa’s Sasol to develop natural gas in the Montney.

BHP also announced an “off-market tender buyback” of shares worth $5-billion (Australian

Permalink Reply by jeff boler on February 22, 2011 at 21:55

I have no idea what a "Cassandras" is or means.

 

I appreciate your input. And I do not simply dismiss negative views regarding Mainland. Instead, I follow up on them, do my own research, and reach my own conclusions.

My concern is those posters who have and continue to strongly suggested that this project will end in failure have not done their fair share of research.

Permalink Reply by Flip Phillips on February 23, 2011 at 2:36

Looks like they're sticking to the vertical scenario vs going horizontal. 

Permalink Reply by 1sk58mq3tyx9y on February 23, 2011 at 2:39

Yes. According to Mainland's latest news (2-23-2011) I read it to be Vertical Fracking.

Permalink Reply by Flip Phillips on February 23, 2011 at 10:14

Question for the frac guys:

When there is a 1000 feet to frac, do they shoot the holes (lay terms) the entire length at one (big bang) time or do they do it in sections? How about the h20/fluid forced pressure part....is that all done at once? Thanks

Permalink Reply by Bruce Badeau on March 2, 2011 at 5:59

I have been researching completion issues by calling experts in the industry. And I promised not to quote them...

I also came across this interesting article starting on page 8 - it discusses the Amoruso Field... This is the analogous field. There are some huge daily producers in that field. I would dearly love to find out what the reservoir characteristics are at 17,000 feet to produce  

25 - 30- 40  million cubic feet per day...

Here is what I have learned (I'm trying to update my estimated reserves for the Mississippi well which I first published Dec. 27, 2010)...

 

About fracing:

1... Head pressure (fill the well with water ) will be approximately 8,800 psi bottom hole pressure.

2... Best fracturing equipment available is rated at 20,000 psi... expensive and long lead time needed to secure the equipment, but it is available in North America.

3... Can increase bottom hole head pressure by "weighting-up" the fracing fluid...

 

I was told that these three facts indicate there is enough mechanical pressure available to do a frac, however other considerations include:

 

A substantial amount of friction through the equipment and system will reduce the pressure available for fracing.

 

Fluid penetration rate per hour at 22,000 frac will be 20-40 barrels per hour... normal is 60-100 barrels of frac fluid per hour...  so the equipment will be on station longer...

 

Fracing can go out from the well bore approximately 300 feet in radial pattern...

6-8 shot point per cluster ... 8-10 clusters per 100 - 200 feet... MNLU will very likely do a multiple stage frac.

 

My big question is recoverable reserves per vertical well?  If we merely produce from a cylinder 2,000 feet with a radius of 300 feet, then that isn't very exciting.

 

HOWEVER, what I have heard is there are strong indications of fractures in the system which will help to extend the fracture area and produce from a larger rock volume. This is really the critical point for the well - having enough fractures to connect a large area than created by the hydraulic frac.

 

What I have heard about Haynesville:

 

Wells haven't been on production long enough to determine ultimate production of free gas. As an example, but not truly analogous is the Barnett Shale which can has a 25-30% recovery of free gas and will require successive fracs later in production history.

 

Shallower Haynesville producing from 300 foot thick sections may recover 150 BCF to 200 BCF of free gas per 640 acre section.

 

Haynesville has reasonable porosities of 5% to 12%  AND  nano darcies of permeability. Remember that porosity is the ability of the reservoir to hold gas and permeability (along with) pressure is the ability to produce. On expert told me that nano darcies are about a permeable as your sidewalk.... the only difference is a huge pressure differential of 20,000 pounds per square inch...

 

If anyone wants to share information privately, you can contact me by phone:

 

281-236-8260  or by email  bruce at fser dot net

Attachments:

• AMARUSO FIELD Emailing 02FebExplorer09.htm, 22 KB

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