I recently learned from an impeccable source that MMR had obtained a complete core in a shale-ly section of Davy Jones #1. Additionally, that core was "highly fractured." Given that and the fact that the well also experienced an impressive flowing event, it is no wonder that the operator had the confidence to install the production platform before any flow test. When asked on a conference call how much would Davy Jones #1 flow, Jim Bob answered, "As much as I want it to." I believe him.
Lufkinunit, we were all embarassed for you (and I figure I got about a 35% chance of spelling "embarassed" correctly!).
I just don't get what mechanical problems there could possibly down 30,000 feet!!!! Shoot, 20,000 at East Lost Hills did us in long ago.
You can be running with a 500 psi plus over-balance to the zone and while circulating, you will be measuring gas units on the drill floor. There is the gas within the drilled section and remember you are circulating fluid past the formation face, before the mud cake is formed on the sidewall you have some venturi effect. pulling some small amount of gas into the wellbore. It does not take much to be sampled and measured. You will most always see some background gas in your returns, but there is no doubt when in hydrocarbon bearing zone. That by itself does mean it is a productive interval, but it is another piece of data along with your logs and cores.
oiljars, I think I’m about to learn something from you.
I though you’d adjust your mud weight to continuously maintain overbalance in the wellbore. True overbalance would not allow gas, and in this case N2S laden methane to flow/dissolve into the drilling mud, so the only N2S signal the mud logger would get from the mud-gas separator would be from the pulverized wellbore section. I was thinking the signal-to-noise ratio for the presence of N2S would be tiny, (all that mud and so little dissolved gas) and therefore even if a combination of well cuttings, SP, and Resistivity signaled a potentially productive formation, you’d still have to flow it to truly know what was there. This is why I thought what I responded to Zamba.
Perfing additional sands within the same formation makes more sense than Packing, Perfing, and Praying. So that clarification was helpful as well.
They should already know if there is any H2S present from the drilling phase. While circulating to the mud pits during drilling there is a mud logger monitoring the gas units and composition with a sampler and hot wire. You can bet they already have a good idea what is present. I think Zamba was referring to perfing additional sands within the same formation.
I don't know in what context the Management Team was using term "gross resource potential". I don't know that it is anything but what they said in a general sense. EUR (estimated ultimate recovery) is normally determined by completion type, the quality of drilling and completion (minimal skin/formation damage), well spacing and how the wells are brought on and produced.If this is a naturally fractured formation as Zamba indicates, it will really assist in the production rate and depletion of this reservoir.
Thanks for the meaning of "gross pay."
Is there a technical definition of "gross resource potential" (a term used by MMR management relative to BBW, BBE, Lafitte, etc.) and how does it relate to an estimate of the potential recoverable production?
“If necessary, all they will do is come up the hole and perforate more to end up filling the pipe to capacity. Hence, Jim Bob's "it will flow anything I want" statement.”
This makes sense with respect your initial post Zamba. One though I just had is that if they’re going to perforate more than one producing zone at a time USING THE SAME PRODUCTION TUBING, they’ll need to do one of two things:
1) Test both zones prior to initially putting the well into production – basically 2 flow tests, or
2) They would need to cease production in zone 1 in order to test zone 2 prior to introducing zone 2 into the production stream.
They would need to know beforehand that zone 2 wasn’t laden with hydrogen sulfide.
Obviously they could tap zone 2 with dedicated production tubing, but that runs counter to what you just said about tapping additional zones to bring the flow rate up to the current 2.875” tubing constraint.
If they’re pursuing option #1, that may be contributing to the delayed timing we’ve been experiencing since December.