Bellatrix, page-22

Trimill

That is the unknown at B1, ie presence of HC's. The rest aligns with their fundamentals that r factored in to calc the CoS alongwith the DHI factor. Basically what Cairn r saying is (post SNE oil find), that the mapping indicates presence of a struc, trap, reservoir, seal, migrn/source, geological age etc.

Together u can attribute a rating to each variable (eg 60%x 50% ...) & once that's done u tweak the 3Dseis & suss out the flatspot or brightspots to see if there's any indication of HC's. That becomes yr DHI factor (eg 1. 1.5. 2). So u multiply the first with the DHI to get the final GCoS. That's it.

The obvious risk remains in the fluid type (ie gas, oil or brine) since B1 type of struc has never been drilled in that part of the world.

Chevron's Jammah#1 well had gas traces in the Creta sands but its 20kms south of SNE-1. And SNE has oil in the Albian sands with a gas cap.

So Petrlm Geol-101 textbook scenario#1 is to treat B#1 as a erosional topographic feature with 'something' in it, since this 'hill' is erroded over SNE1, 2, 3 & sits in the northern portion.

Alternately, as SNE#2 is the closest well to B1 with gascap & oil bearing sands, some old timers would go with the SNE being 'filled up & some juice spilled out updip & got trapped in a diffrnt sand' scenario.

Each theory will have its merits & supporting arguments. They second theory will hold if B1 oil sample is 32API, ie same as SNE. That will make it all Elementary for the Sherrock Holmes out there.

So lets see what happens when they drill past 2260m at B1. The top part should b cased & then whatever cuttings shows up on the shakers & gas peaks over chromatograph & streamin cut in the Fluoroscope will matter more (the usual signs of visible oil, smell, C4, C5 gas peaks etc etc). So thats the CoS part.

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Gutz,

They need to intersect SNE sand column first at BEL#1 & see what the Wireline logging & VSP/chk shots show in regards to their correlation with SNE#3 which is now the nearest offset well.

The JV can opt to run a  PLT tool run to see if there's any flow in that part of the sand. Fluid samples can b obtd from the MDT tool, which when retrieved on surface will show oil or water.

Assuming these sands r water bearing, then during field development they can use this data to locate future Injector wells. The thick/thin sands can b developed accordingly after the JV decides on a Development concept. Lots to do b4 that.

Back to yr question, we know this is an offshore well. So post completion of drilling/logging etc, they'll run a tool with the multiple pressure sensors. Leave it suspended in the sections of interest (eg 2450-2700m), set up a wellhead with a wireless sensor that sends off the data real time to a remote location (office or a chartered Vessel) periodically. That's the simple version. It's a complicated topic for HC & I wont go into the necessary details. But that's basically the jest of it.

As an case study, at Jubilee 4 wells were tested for 'uncertainities' via Injectivity tests, since the field has multiple sand lobes of varying areal extent two OWC's whick made things challenging. 1 smaller lobe at a particular location wouldn't show up on another well & they opted to test 2 main thick sands. The 'Unitised' block is only 110km2 or 27000 acres gross area with varying 'netpay' from 24 + 8 wells, hence to need to remove uncertainities at the reservoir level. Eventually all the hard yards that went into the dev drilling, Injectivity & pressure testing is the reason why its producing 102k bopd five yrs later (including gas & water injector wells).

For now at SNE, alongwith the core data from SNE#2& SNE#3, new 3Dseis + remapped 3D, VSP & other wireline data (gamma, res, density, sonic etc), MDT fluid samples, pressure reading & flow rates should give sufficient confidence to the JV to select future well locations, field dev concept & book field reserves (ie DoC 1P, 2P etc).

Also note that 10% IRR at USD40/bbl in my view they must used a lower Discount rate in the model (ie 7 or 8%). NPV-101: reject a project where hurdle/Disc rate is same as IRR. So an Operator runs various sensititvity scenarios for POO changes & costs to come up with a break-even number. They already know the local PSC terms, max cost recovery per annum, profit sharing, country tax% to validate their Fin model.

That's about it, time to switch off, whatever happens, happens.