In consol energys quarterly report they mention that the TUSC 3A well had 38 api oil and 1440 btu gas. Just wondered if someone could help me out on what 1440 btu gas means for us landowners
Dry gas is approximately 1000 btu.
1440 btu would suggest the presence of significant amounts of Natural Gas Liquids (Ethane, Propane, etc.)
1440 btu would be characterized as "wet gas".
To expand on Jack's numbers here - dry gas is predominantly/entirely methane. Higher btu values (above 1000) mean heavier hydrocarbons are present, including the NGLs Jack listed.
For example, you could have a 1100 btu gas that is primarily methance but has some ethane component. Likely not enough to make a significant impact on economics or selling liquid fractions. Values of 1300-1400 are rich gas and, as noted, will likely have a NGL component.
Hope that helps.
FYI, 38 API gravity means the oil is light.
Thanks for the question Shawn. I was wondering that myself.
And the million dollar question......
What do those numbers mean for the landowner....in terms of royalties?
Absolute amount of royalty would be dependant upon the quantities of the respective constituents.
Light sweet oil is currently worth about $100/bbl.
Light sweet oil trades at near Brent crude price (as opposed to West Texas Intermediate - NYMEX WTI).
NGL prices are currently depressed - about $50/bbl.
Dry Gas (Natural Gas/Methane) is very depressed - today's spot $3.14/mcf (mmbtu).
Oil is the most valuable on a btu basis.
Next comes NGLs.
Dry Gas comes in a poor third.
I agree .....so to me, sounds like this well has hit the trifecta!
It is just a matter of what % of each and volume of the well.
The Wet gas window yet to be defined.....as this well is Middle of Tusc. County.
Here's an example from an investment study of all the shale plays in America.
1,000 mcf of 1,250 btu gas produced (after processing) 770 mcf of dry gas and 125 bbl/NGL. The higher the btu the "wetter" it is, thus the more NGL's potentially processed.
I wouldnt get too excited, Paul, there is a pump jack on that well, so the gas may be 1400, but there isn't a whole hell of alot of it to move the goods... the flare was the size of a bic lighter at a Guns and Roses concert
This well falls in the oil window of the play so the gas is not going to be as significant and a pump jack is going to be needed to move the liquids. I would not put much wait on the size of the flares especially with the EPA restricting companies from flaring gas to cut back on CO2 emissions.
It was producing 300 barrels of oil a day, then it dropped off. My contact at CONSOL says they will not use the technique they used on this one for future wells. It's producing enough to go into production though. But, I don't think this well is one to use at the golden example. They also told me pump jacks will be used with most of the wells in this area.
The pump jack may be in place to remove fluid that might impede gas flow from the formation due to the pressure exerted by the vertical fluid column. The fluid may be condensed water vapor, residual and unrecovered frac fluid, free liquid hydrocarbon, etc. Methods other than pumping are also used to de-water gas wells, such as smaller diameter production tubing, surface compression, or surfactants like soap that foam and reduce the density of the liquid column and allow it to entrain in the gas stream and flow more easily to surface.