How will they break down mixed liquids for your royalty if your lease says from well head?
How can the oil companies figure out your royalty when it comes to mixed liquids if your lease says from the well head with no processing costs to you.
They don't know what's there until its processed right? Wouldn't it get mixed into the pipe lines with other mixed liquids from other wells or.... I have no idea actually that's why I'm asking :0).
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Permalink Reply by bungalow_steve on
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There is no absolute "wellhead" price. The way they compute it is they sell the post processed liquids at the market price, say $12, then they figure out how much it cost to process it, say $1, the wellhead price is then back calculated $12-$1 = $11. So $11 is what the liquids where worth at the wellhead and that is what you get. This is called the net back method of calculating royalties.
Some gas companies would subtract another $1 from the $11 and give you $10, this is what the "no processing costs to you" prevents, it doesn't stop the gas company from computing royalties using the net back method.
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Permalink Reply by 2s72s0k9mm8gd on
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Good question. Is the outflow of each well analyzed for chemical makeup at the wellhead periodically? How else would you know you are getting the correct $$ for what flows from each well in your unit? Is NGL just NGL , or are there various grades valued accordingly? Crude Oil has different grades with different values , how about NGL's?
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The make up of NGL'S can be determined by running a sample of the gas stream through a chromagraph. This will give a break down of the % of methane, propane, butane, ethane/ect.
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Would this be a test that could be setup to run unattended and recorded for royalty calculation on a regular schedule?
I wonder how consistent the makeup of any well's NGL's remains? Is it constantly variable or stable at set percentages? Hard to imagine there being alot of consistency from one area (region) to the next , but , on a per wellhead basis how consistent is it?
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You can set one on a well site, however they are expensive and labor intensive. A good rule of thumb is 10000 MCF install a chromagraph. Most of the measurement that I have seen at the well head is orfice plate measurenent with an electronic corrector. This is important because you can plug sample values into the electronic inst. and the inst will measure to those values.Ex. BTU,S specific gravity pressure, temp.orfice plate size methane, propane ,butane, ect. all part of the measurement formula. On lower flow well sites a landowner should request a sample be sent to a lab, then the new values entered in the corrector, at least once a month. Just a % point or two on any of these values will make a big difference in royalty payment
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Yes I meant 10000 MCF per day. 1000mcf would be low flow, take a monthly sample,send to a lab then enter values into electronic corrector. Calibration on chramagraph at least 2 times per month, full cal. run not just a daily check. 1% would be a large % of error on high volume flows. I like to see no more than 0.2% TO 0.5%error. very easy to obtain with todays technology. Utra sonic measurement no more then 0.2% error. One of the best addendums in a lease would be measurement to AGA spec.
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Thank you matthew.
So there are different "grades" of NGL's and the value can vary accordingly. Interesting and something everyone receiving royalties should know!
Now , is there anyone who is receiving royalties from "wet gas" that would share with us how this works for them? Is your NGL being analyzed regularly for content , and , is there much of a fluctuation in the value?
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Permalink Reply by 0l1a6laz7smpf on
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http://www.youtube.com/watch?v=ga7HibLmSd8&feature=relmfu
I wish we all could have watched these videos before any leases were signed...but they were not available for most unless they knew to look online perhaps for Texas gas drilling.
i am thankful that Chesapeake has went to the effort to have these videos at youtube. Pls do send the links to your neighbors so they can learn about the process also. There is more than one video about the process..
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this is such a good question Kathleen...and one to find an answer to ....that way we all understand the process better.
here is a very informative link, worth reading....yet that is an absolute great question about them mixing the gas that is processed at the well head of one well and it going in the same pipeline to the next processing area...of course maybe it is one pipeline per well pad to the next processing plant.
http://www.naturalgas.org/naturalgas/processing_ng.asp
this link has info about royalty payments and lists what kind of deductions, etc.
http://www.mineralweb.com/owners-guide/leased-and-producing/oil-and...
and this also is excellent to understand what kind of problems in calculating how much gas and why the difference in royalties and deductions:
http://fwbog.com/index.php?page=article&article=248
this statement is in that article:
“Many of pipeline/processing companies will buy gas at the wellhead, so they themselves own a percentage of the gas in the pipeline,”
there you have where a first sale can begin before any further processing...at the wellhead and purchased by the pipeline/process company (which could be the same company as the Lessee in many cases, such as Chesapeake). Now would one consider that 'fair market value"? That's when you wonder if you have a 'net' contract where you pay partial for expenses for processing, gathering, transportation, etc. if it would be fairer for them to just sell it at the wellhead without all those extra fees? and if you have a 'gross' royalty in your contract then you hope they take it further downstream to market at a higher price....again the oil companies have trumped most of us with their knowledge against our lack of knowledge of the process.
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Permalink Reply by Kathleen on
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Hi,
I got my lease out since I remembered there was a gas measurement clause. The method to be used in my lease is called "Boyle's law" for the measurement of gas at varying pressures, on the basis of 10 ounces above 14.73 pounds of atmospheric pressure, at a standard base temperature of 60 degrees Fahrenheit and stipulated flowing temperature of 60 degrees Fahrenheit , without allowance for temperature and barometric variations. This measurement shall be at the wellhead.
That part was word for word in the lease. So I looked it up. I will use the excuse today of saying I cannot understand this due to a head cold.
I found one example using air and mercury. Again my head cold won. To me it sounded like at the certain temperature and pressure each molucle will bounce off the walls of the syringe (used in the example I read) at different rates and can be measured.
Boyle's law was invented in 1662. How in the world they would do this at the well head is beyond me but now I will try to find a modern way in which the Boyle law is used in the field.
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If there isn't enough to figure out already....
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Permalink Reply by Jack Straw on
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Kathleen,
This reference to Boyle's Law is a scientific description of how to correctly measure the volume of a gas (Physics 101).
It might appear to be an overly obtuse definition; but it simply means measurement of the volume of nature gas is to be corrected to "Standard Pressure and Temperature".
I would rather see the description (as you quoted) in the lease than for it to be absent.
To break it down to its simplest meaning, you could mentally substitute the phrase "We will fairly and honestly measure the volume of gas." - as that is what the clause promises.
All IMHO,
JS
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