How can you compare one well to another if they are not tested with the same choke?
Example: SAMPLE #4, RED RIVER, SN238828 tested 23,876 MCFD with a 26 Choke and 7,389# Flow Pressure.
NABORS LOGAN 34H, SABINE, SN238703 tested 6,043 MCFD with a 10 Choke and 8,290# Flow Pressure, with a 9,000# Shut In Pressure.
If a 26 Choke is a hole with a 26/64" diameter opening, and a 10 Choke is a hole with a 10/64" diameter opening, then the 26 Choke is 6.76 times larger in area than the 10 Choke, and will allow much more gas to flow.
Flow pressure will change when you open up the choke, and there will be other variables to figure in, so there may not be a way to actually compare these two wells.
What do some of you others think about this?

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I think that's about right, Jim, but I'm still qurious.
Thanks.
You can get the information you want by hiring a petroleum engineer. There are other variables that are needed before this calculation can be made, ie depth, perferated intervals, frac information, etc.

Jim is right. Gas sold over the life of the well is the ONLY thing that matters.

Todd M. Baker
LOL-slap!!
Okay, guys. Quit sniffing that gas. Or I'll have to sic the Yankeees on ya.
good question
Actually, in trying to compare the wells' performance, the choke size is the least important piece of information. The pressures and rates are more important. If you had additional information on tubing size, depth to perforations, gas quality and liquids, etc., a handy dandy reservoir engineer or production engineer could convert that production rate and flowing tubing pressure into a flowing bottom hole pressure. Then, with an estimate of reservoir pressure, could come up with the delta pressure that is giving up the quoted rate. That would tell you something about the well's potential, but could have a masking effect due to any mechanical issues, wellbore damage (skin), etc.

But all things being equal and with only the information given, I'd take that Sample #4 well before the Logan well. Not a big difference in FTP but huge difference in rates.
I'm with you, Mmmarkkk, I'd take my chances with the Sample 4.
How do the financial analysts ever get an accurate prediction of overall recoverable reserves per well if they are using a mathematical computation using only the initial flow rate and an average decline curve for a certain play. I know that the answer is going to be that they don't know anything but that seems like a dangerous play when you are talking about trillions of dollars in the market.
ALongview. I think the industry generally does an outstanding job of analysis. Though much has changed over the decades, the industry still must deal with a lot of risk. And the culture seems to thrive on making "big bets" as much now as it did in the early days. There have been a number of plays discussed on the site that were considered the next "big play" in their day only to fail to some degree. It's a "win a few, loose a few" industry mind set that is playing out in real life for us in the HS as we watch. I won't go into specific examples as I do not care to remind anyone of the disappointments to date but we will see great successes, a number of somewhat disappointing results and a few out right failures. It will be years before we know the details. May the successes be many and the disappointments few.
ALongview:
The analyst only use the information given them by the engineers. The factors or information used are: net acre feet, porosity, permeability, bottom hole pressure, water saturation, formation temperature, etc. Decline curves have no bearing on anything other than "guestimates" of future events. A decline curve can be drawn and will be accurate only after a well ceases to produce. These data are put into formulas to arrive at a gas in place (GIP). These are "utopian" figures, if you will being only figures derived on a calculator. Utopian because you can never recover all the gas in place. Then over time, they can take the volumes produced and re-check bottom hole pressure, etc to get what is called estimate or expected ultimate recovery (EUR).

This early in a play, all the EURs are based solely on calculations and guestimates. Time will tell whether or not the EURs are close to being correct. Some companies employ more agressive numbers while others are more conservative in their estimates.

The analyst have only this information to go by and then they try to gauge the "truthfulness" of the calculations to arrive at their evaluation of the companies assests.

Hope this helps some.

Todd M. Baker
Huge help Todd, thanks! I was getting my info off of conference calls, Q&A's etc. where the management had a number like .40 that they multiplied by the ip rate to "guesstimate" the EUR of these wells. I think the "number" was derived from the study of the Barnett Shale and the trends that they saw over there. Does this sound familiar at all? It sounds like there is much more to it which to be honest is much more reassuring.
I don't know about the "number" or how they have arrived at it. But they are trying to use something to compare the Barnett with the Haynesville, ONLY because analyst are asking for a comparison. The Barnett is the closest "history" we have to use.

As they say, "comparison is the root of all unhappiness." There is really no way to compare the two because they are very different in many ways, depth, temperature, porosity, permeability, pressure, thickness, arial extent, etc. The only things they have in common is they are shale and they are both south of the mason dixon line.

Yes, you can rest assured, there is a scientific process to the madness of guestimating EURs and it can be very complex. In 2-3 years, the picture will be made more clear as more data is entered into the equations.

Todd M. Baker

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