They have apply Net pay for TVD, as the wellbore is inclined at an angle which is why the MD'pth is higher. Basic trignometry..
Their first challenge was to encounter HC's which is good to know as per the shows & Wireline Logs, as it beefs up the Oil in Place for a known Areal extent of the field (eg: 1, 5, 10, 30, 44 km2).
Next up is to demonstrate the deliverability of the various Reservoir's as in movable HC's, flow potential on variable choke setting, oil sampling, viscosity, Sulphur content, TAN, overall Oil quality, any associated gas, reservoir Temperature, Reservoir pressure depletion, water cut etc etc. This goes towards applying a recovery factor. For arguments sake lets just assume it at 5% as per the analogue fields nxt doors.
Together, these two alongwith the existing or New Seismics over the field should give them an idea of how may wells will b reqd eventually to flush out the Oil in Place over xx years and the related budget to do that sort of drilling once its declared commercial. Until then its all Oil in Place which hasn't gone anywhere since Marti-5 was drilled back in the day. So that's the sort of risk they'd b looking at. In short its an interesting problem to have, when compared with saying we drilled a duster end of story.
The mkt however wants to see flowrates as a starting point and then plans for follow-up drilling at the earliest possible.
In the real world. Discovery to Commercial production takes time & there's not much AP can do until he has all the answers from Flow testing.
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