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Permalink Reply by 0i7okn54zwbdo on February 5, 2014 at 3:39am

Crude is the 'heaviest' thing that goes through the line, though heavy is relative.  Condensate has a fairly high gravity so it moves through the pipeline pretty easily.

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Permalink Reply by INVICTUS on February 5, 2014 at 3:57am

I'm trying to get better understanding around the line that we have installed.

I'm told we have a gas line.

Then we are told the "oil" will be trucked out.

So I get back into my old school chemistry books from "days of yore" to read up a bit on

the constituents/fractions that come out of these wells.

In defining these, I never get solid consistent answers from the fellows whom I ask of these things, ie, the superintendents who progressively came and went as the pad was developed.

So here goes:

I interpret methane through at least butane to be gaseous and into the Pipeline they go.

I interpret the heavier gases which I believe are the NGL's to be either light component of "oil" or do I call them "condensate?

And, at which point does the NGL's get so heavy that they are called "Oil" and have to be trucked out?

We have one Pipeline. The Midstream people "Talk" about the need for a second line: A condensate line. 

I guess I need to get the definitions correct before I can ask the correct questions.

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Permalink Reply by Mark McGrail on February 5, 2014 at 4:43am

Invictus,

I'll give you my interpretation of it all, a layman's understanding. If I mess up it may irritate someone with better knowledge and influence them to reply.

I have seen "condensate" used to describe  two different products - natural gasoline and the natural gas liquids contained in "wet gas". I assume that it usually means NGL's.

Natural gas, natural gas liquids, oil are all hydrocarbons. NGL's are heavier than NG, oil is heavier than NGL's. When the gas comes out of the well oil is heavy enough to be separated mechanically at the well site. From there the NG and any associated NGL's go into the pipeline and are sent to a cryogenic plant. At the plant the temperature of the gas is lowered and the NGL's "condensate out and, the "dry" gas (methane) is sent on it's way into a pipeline. The NGL's "condensate" is/are sent into a different line to a fractionation plant to be further processed.

My apologies to those more knowledgeable than I for any mistakes.

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Permalink Reply by James Vanderink on February 5, 2014 at 2:17am

Does anybody know if Enervest has broken ground on either the Dickerhoof and Rummell Farms laterals. Anadarko/NGO have a permitted Clinton Horizontal in Coshocton county using an existing well bore. I haven't heard anything on that either.

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Permalink Reply by James Vanderink on February 5, 2014 at 3:49am

Since this is the "Ask Snort Show" I have a question. A horizontal bore into a Clinton GAS only field.... your opinion on the economics of that. A few years ago in a conversation I heard it could be like the Marcellus.

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Permalink Reply by MJ on February 5, 2014 at 4:15am

It is nice to see you sharing your knowledge on an appreciable level finally.  I know your a credible source and now hopefully some others will get some much needed info about the area from you.  Thanks

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Permalink Reply by Paul Martinelli on February 5, 2014 at 7:06am

Snort,

If all of what you say is true......Why would there be offeres out there to buy mineral rights in Tusc. County? .....I'm in eastern Tusc......and have had offers.

 

These companies that purchase mineral rights generally are not looking for a "buy and hold" investment, where they see a return in 5-15 years down the road.

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Permalink Reply by Paul Martinelli on February 5, 2014 at 7:29am

"I  wouldn't sell unless you need the money.  I feel that way about anyone who owns mineral rights...never sell unless you have to.

 

I agree 110%

 

 

" It will probably be economic but marginal."

I think we will know the answer in ~18 months.....Seems Enervest will need to "derisk" the area  or go down swinging.

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Permalink Reply by INVICTUS on February 5, 2014 at 7:47am

So I get $15k /acre to sell the rights.

I know one is MAC.

I think another is Aubrey/or affiliates.

And I know of Royalty Trusts and/or MLP's of some kind also interested.

But If I sell, I lose full control of Surface rights, plus now have a partner.

What I's like to know: their cash flow model to offer these kinds of numbers.

My discount models don't know the expected internal rate of return, nor what the "life of the well" means in terms of cash flow periods (how many years to discount back to arrive at net present value.

I figure either they're not too bright in this line of work (overpay)

or

They're insiders who know at least something to offer that kind of loot.

My pathetic analysis comes to: $30k acre to seriously consider a sale.

Yes, I've taken into account cap gains at sell decision vs royalties using

1) Regular Sched E income  &   2)1031 exchanges/or some forms of irrevocable trusts to shelter income.

$30k/acre over 8 - 12 years is my cash flow expectations.

Being developed is no longer in question (Key to this guesstimate)

Neighbor production unit is developing $500/acre/mo (3 lateral unit) to leaseholders with 15% royalties/gross.

Must be choked back as they don't see decline YET??!!

Again the question: What are expected cash flow models by people more sophisticated than Joe/Jane Landowner?

Please, let the arrows fly and offer comments!!! 

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Permalink Reply by Paul Martinelli on February 5, 2014 at 8:03am

What area/county you talking about?

 

If it is indeed in the  the "retrograde condensate" window......then I'm not sure they have solved that problem, and any wells drilled will have a STEEP decline curve......which would limit the value of a mineral rights sale.

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Permalink Reply by Paul Martinelli on February 5, 2014 at 9:05am

Interesting reading......

http://www.arcticgas.gov/point-thomson-key-gas-field   on retrograde condensate

 

"

Problem No. 1: If the condensate becomes liquid underground rather than at the surface, it can cling to the rock particles and clog the area around the well bottom. This reduces the amount of gas that can flow to the well, costing the gas producer revenue.

Problem No. 2: Once the condensate becomes liquid down in the reservoir, less of the condensate will be produced. Again, this costs the producer revenue.

The solution is to keep the reservoir pressure from dropping too far. ExxonMobil and its partners propose to do that by "cycling" the gas production this way:

• Produce a relatively small flow of gas from Point Thomson – perhaps 200 million cubic feet a day.
• Extract from that about 10,000 barrels a day of condensate at a plant they would build at Point Thomson.
• Flow the condensate 60 miles to the trans-Alaska oil pipeline and on to markets. (Natural gas liquids have been mixed with crude oil and flowing through the pipeline for more than 25 years.)
• Recompress the rest of the gas and inject it back into the reservoir to preserve the pressure.

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Permalink Reply by TM on February 5, 2014 at 9:18am

Here is a paraffin clean out on a well video. This well was located in western PA.

http://skyepetroleum.com/paraffin-clean-out-video.html

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